58 results about "Skin factor" patented technology

A method for forecasting performance for and characterizing the properties of a multilayer low permeability gas reservoir. The method includes a coupled well / reservoir predictive model that accounts for pressure drop between layers, allowing accurate, rigorous, and rapid forecasting of reservoir performance. The method provides estimates of individual layer properties such as in-situ permeability, skin factor, fracture half-length, fracture conductivity, drainage area, etc. by simultaneously history matching production data and production log data using the coupled well / reservoir predictive model.

The invention provides a well test analysis control system for a low permeability gas reservoir and a method thereof. The method comprises the following steps: measuring bottom hole pressure value of a gas well in a period after well startup to obtain a relation value between pressure difference and time; judging whether the relation value equals a preset relation value, if yes, performing the next step, or correcting well test interpretation parameters corresponding to the preset relation value; taking the well test interpretation parameters corresponding to the preset relation value as the well test interpretation parameters of the gas well; analyzing gas permeation situation of the gas well according to the well test interpretation parameters so as to control exploitation of the well gas; wherein, the well test interpretation parameters comprise gas slip factor, low level permeability, skin factor, well bore storage coefficient, flow coefficient and formation pressure. The well testinterpretation according to the method perfectly accords with actual condition of the gas reservoirs, accurately describe the gas reservoirs, and provide a reference for determining production system.

A method and a computer program for economic evaluation of completion methods for drilling a well. An extensive user interface is provided for inputting of reservoir data and parameters relating to a first completion method. A rigorous first skin factor is generated based on the reservoir data and first drilling parameters. An interface is preferably provided for entering cost data related to the first completion technique and a first total cost can be generated. Production data is optionally generated from the first skin factor. The production and cost data can then be combined to generate an economic analysis of the first completion technique. The process can be repeated for alternate completion techniques. Preferably, ranges can be entered for certain reservoir and / or cost variables. Multiple iterations can be performed on the ranges resulting in total cost and production ranges which can be combined to yield ranges of economic data for statistical analysis. This results in a user being able to choose the most advantageous completion method.

The invention relates to the technical field of oil reservoir productivity prediction, in particular to a prediction method for volcanic rock oil reservoir productivity. The prediction method comprises the following steps: step one, collecting the oil reservoir basic parameters of oil reservoirs or similar oil reservoirs of tested oil wells in target blocks, including individual well productivity Q, perforation reservoir thickness h, crude oil volume factor B0, comprehensive skin factor s, perforation productivity ratio PR, starting pressure gradient lambda, after-pressing well testing permeability Ks, formation pressure pe, flowing pressure pw, wellbore radius rw, fluid viscosity u, and fracturing fracture length, wherein the unit of the after-pressing well testing permeability Ks is mD, the units of the formation pressure Pe and the flowing pressure Pw are MPa, the unit of the wellbore radius rw is m, and the unit of the fluid viscosity u is MPa*s. Compared with an existing analogy method, the prediction method is more targeted, and the precision is higher, the precision can be improved to 60% above through the method disclosed by the invention, and a good method is provided for exploration oil testing, layer selection and the like.

The invention discloses a colon cancer protein mark parallel test liquid phase chip, which is mainly formed by: micro ball, capture antibody, test antibody and streptomycin-phycoerythrin, wherein the capture antibody with the corresponding micro balls form coupling conjugated, which uses red laser to active the red categorizing fluorescence of the sphere base material and ascertains the type by the different color of the sphere base material; the test antibody is a skin factor mark antibody; the capture antibody and the test antibody can combine with the colon cancer protein mark; the test antibody combines with the streptomycin-phycoerythrin and uses green laser to active the phycoerythrin to measure the report fluorescence molecular number of the sphere base material, which can indirect ascertain the colon cancer protein mark content combines with the sphere base material. The invention also discloses the colon cancer protein mark parallel test liquid phase chip applied in preparing the test agent.

The invention relates to a well test analysis control system and method used for horizontal well subsection liquid producing identification. The method includes the following steps that a bottom hole pressure value of a horizontal well in the well shut-in period is measured, and the relation value between a pressure difference and time is obtained; whether the relation value is equal to a preset relation value or not is judged, if yes, the next step is performed, and if not, well test interpretation parameters corresponding to the preset relation value are corrected; the well test interpretation parameters corresponding to the preset relation value serve as well test interpretation parameters of the horizontal well; according to the well test interpretation parameters of the horizontal well, the liquid producing condition of the well is analyzed so that development of the horizontal well can be optimized; the well test interpretation parameters comprise the horizontal well liquid producing section number, the position of each liquid producing section, the length of each liquid producing section, the skin factor of each liquid producing segment, the permeability and a shaft storage coefficient. Horizontal well test interpretation performed through the method accords to the actual condition of an oil reservoir better, and an accurate basis is provided for liquid producing well section diagnosis and interpretation and well stimulation making of the horizontal well.

In one method, the permeabilities are obtained by correcting the geometric factor derived from combining the FRA analysis and buildup analysis. In a second method, the permeabilities are obtained by combining the spherical permeability estimated from buildup analysis and the geometric skin factor obtained from history matching the probe-pressure data. In other methods, horizontal and vertical permeabilities are determined by analysis of pressure drawdown made with a single probe of circular aperture in a deviated borehole at two different walls of the borehole.

The invention relates to a method for obtaining well test interpretation parameters of a polymer flooding three-layer channeling reservoir. The method for obtaining the well test interpretation parameter of a polymer flooding three-layer channeling reservoir comprises the following steps that (1) according to rheological properties of a polymer solution, modifier formulas of a polymer solution viscosity model are determined, and according to characteristics of the polymer flooding three-layer channeling reservoir, a physical model of the polymer flooding three-layer channeling reservoir is established; (2) according to the modifier formulas of the polymer solution viscosity model and the physical model of the polymer flooding three-layer channeling reservoir, a mathematical model of the polymer flooding three layers channeling reservoir is determined; (3) the mathematical model of the polymer flooding three-layer channeling reservoir is solved through a finite difference method, and the numerical solution of the bottom hole pressure is obtained; (4) wellbore storage coefficients, formation coefficients, storage capacity ratios, time and the bottom hole pressure are nondimensionalized, and typical curve theoretical map of the polymer flooding three-layer channeling reservoir is drawn; and (5) the reservoir permeability, the skin factor and the wellbore reservoir coefficients of the polymer flooding three-layer channeling reservoir are obtained by fitting the typical curve theoretical map of the three-layer polymer flooding reservoir with measured data curves of oilfields.

The invention relates to method and agent box for detecting mammary gland globulin in the field of biology chemistry. The latex fixation leptospiral method comprises the steps of: a) mixing the mammary gland globulin antibody marked emulsion particle with the tested sample, b) quoting the test result by weather it has agglutination reaction, wherein the mammary gland globulin antibody marked emulsion particle is the emulsion particle which uses mammary gland globulin antibody R028 or R048 marked emulsion particle with the dilemma 2-10um; preserving the marked emulsion particle inside the HEPES buffer solution with pH 8.2. It also discloses a method for using the anti-mammary gland globulin monoclonal antibody and skin factor mark anti-mammary gland globulin monoclonal antibody to quantity test the mammary gland globulin by double clamp heart enzyme immune adsorption method. It also discloses a RT-PCR test mammary gland globulin expressing method and provides the agent box used to test the mammary gland globulin.

The invention provides a well test analysis control system for a low permeability gas reservoir and a method thereof. The method comprises the following steps: measuring bottom hole pressure value of a gas well in a period after well startup to obtain a relation value between pressure difference and time; judging whether the relation value equals a preset relation value, if yes, performing the next step, or correcting well test interpretation parameters corresponding to the preset relation value; taking the well test interpretation parameters corresponding to the preset relation value as the well test interpretation parameters of the gas well; analyzing gas permeation situation of the gas well according to the well test interpretation parameters so as to control exploitation of the well gas; wherein, the well test interpretation parameters comprise gas slip factor, low level permeability, skin factor, well bore storage coefficient, flow coefficient and formation pressure. The well testinterpretation according to the method perfectly accords with actual condition of the gas reservoirs, accurately describe the gas reservoirs, and provide a reference for determining production system.

The invention provides a system for visually evaluating a production and blockage law of hydrate in a screen and a testing method thereof. An experimental system for testing a secondary production, enrichment and blockage law of the hydrate in a screen mesh comprises a reaction kettle, a gas-liquid mixed conveying coil, a high-speed camera, a data acquisition and processing module and the like. The testing method is based on the system, and through adjustment of a cooling mode and control of a temperature and pressure condition and a gas-liquid ratio condition, a three-dimensional chart of thesecondary production and blockage of the hydrate in the screen mesh is simulated; the system can provide basic data for calculation of a well-bottom screen sand control additional skin factor and formulation of a precise pressure-reducing and temperature-controlling scheme under different well body structure conditions (a vertical well, a horizontal well or a multi-branch hole) of a natural gas hydrate production well, and provides a strong support for a sand production management system of the natural gas hydrate production well.

Disclosed is a method for transient testing of an oil well to determine the individual, distinct skin factor components of an apparent skin factor, which includes opening the well to a first predefined choke setting to allow the reservoir fluid to flow through the well for a first predefined period of time, and measuring a production rate of the reservoir fluid through the well, when the first predefined period of time expires. The method further includes performing a shut-in of the well for a first predefined build-up period, and repeating, when the first predefined build-up period expires, the steps of the flowing, the measuring, and the performing for at least two additional choke settings. The distinct skin factor components of the apparent skin factor are determined using a graphical relationship between the determined apparent skin factors and the measured production rates.

In one method, the permeabilities are obtained by correcting the geometric factor derived from combining the FRA analysis and buildup analysis. In a second method, the permeabilities are obtained by combining the spherical permeability estimated from buildup analysis and the geometric skin factor obtained from history matching the probe-pressure data. In other methods, horizontal and vertical permeabilities are determined by analysis of pressure drawdown made with a single probe of circular aperture in a deviated borehole at two different walls of the borehole.

In one method, the permeabilities are obtained by correcting the geometric factor derived from combining the FRA analysis and buildup analysis. In a second method, the permeabilities are obtained by combining the spherical permeability estimated from buildup analysis and the geometric skin factor obtained from history matching the probe-pressure data. In other methods, horizontal and vertical permeabilities are determined by analysis of pressure drawdown made with a single probe of circular aperture in a deviated borehole at two different walls of the borehole.

The invention discloses an acid distribution method based on the distribution characteristics of horizontal well skin factors. The acid distribution method comprises the following steps that (1), a single well geological model is established under initial conditions; (2), a single well geological model after drilling damage is calculated based on the single well geological model constructed in thestep (1); (3), based on the single well geological model constructed in the step (1), a horizontal well liquid production section before the drilling damage is calculated; (4), based on the single well geological model after the drilling damage calculated and obtained in the step (2), a horizontal well liquid production section after the drilling damage is calculated; (5), according to the horizontal well liquid production section before the drilling damage obtained in the step (3) and the horizontal well liquid production section after the drilling damage obtained in the step (4), the skin factors at different positions along an entire horizontal well section are calculated; and (6), the amount of acid distribution at different positions of a horizontal well is calculated according to the distribution characteristics of the skin factors along the horizontal well section. The acid distribution method solves the problems of low acidification efficiency and poor acidification effect caused by existing blind acid distribution.

A method for determining skin factor of a subsurface rock formation from within a wellbore drilled therethrough includes measuring a nuclear magnetic resonance property of the formation at a plurality of lateral depths therein. The measured nuclear magnetic resonance property is used to estimate the skin factor.

The invention provides a bottom water reservoir horizontal well variable-parameter perforation water-controlled completion method and device and relates to the technical field of horizontal well water-controlled completion. The method comprises the steps of setting a water controlling unit dividing strategy and a perforation unit dividing strategy; generating a horizontal well-controlled segment water content profile predicting model, and determining the liquid production capacity of each water controlling unit enabling each water controlling unit to reach target limit water cut at the same time; determining the overall perforation skin factor of all the perforation units enabling near-well additional seepage pressure drop to reach the minimum under a preset perforation bullet condition, and determining the perforation bullet combination of all the water controlling units enabling perforation density rounding error to reach the minimum; determining the perforation density of each perforation unit; conducting bottom water reservoir horizontal well variable-parameter perforation water-controlled completion. By the adoption of the method and device, the problem of the prior art that due to the fact that premature water breakthrough occurs on part of horizontal well segments or water content of part of horizontal well segments is too high, water content of an oil well increases sharply and reaches limit water cut too early, and then well segments on which water breakthrough has not occurred yet and low-water-content well segments can not be utilized effectively can be solved.

In one method, the permeabilities are obtained by correcting the geometric factor derived from combining the FRA analysis and buildup analysis. In a second method, the permeabilities are obtained by combining the spherical permeability estimated from buildup analysis and the geometric skin factor obtained from history matching the probe-pressure data. In other methods, horizontal and vertical permeabilities are determined by analysis of pressure drawdown made with a single probe of circular aperture in a deviated borehole at two different walls of the borehole.

The invention provides a levorotatory VC snow skin factor-rich mask capable of improving the skin color and improving the brightness. The mask is prepared from the following raw materials in parts by weight: butanediol, glycerol, dipropylene glycol, a yeast extract, glycine betaine, royal jelly, a hydrolysed placenta (sheep) extract, ubiquinone, palmitoyl pentapeptide-4, collagen, glyceryl polyether-26, sodium hyaluronate, trehalose, poly(sodium l-glutamate), carbomer, xanthan gum, triethanolamine, phenoxyethanol, chlorphenesin, methylparaben, PEG-40, hydrogenated castor oil, essence and water. The traditional Chinese medicine extract is capable of effectively enhancing the effect of delaying senescence; the royal jelly can be absorbed by epidermis of a human body; the epidermis cells are nourished; the life vitality of the epidermis cells is promoted and enhanced; the metabolism of the skins is improved; elimination of metabolites is accelerated; pigmentation is reduced; and the elastic fiber is prevented from degenerating.

In one method, the permeabilities are obtained by correcting the geometric factor derived from combining the FRA analysis and buildup analysis. In a second method, the permeabilities are obtained by combining the spherical permeability estimated from buildup analysis and the geometric skin factor obtained from history matching the probe-pressure data. In another method, horizontal and vertical permeabilities are determined by analysis of pressure drawdown made with a single probe of circular aperture in a substantially horizontal borehole at two different walls of the borehole.

Method for determination of a fluid influx profile and near-wellbore area parameters comprises measuring a first bottomhole pressure and operating a well at a constant production rate. After changing the production rate a second bottomhole pressure is measured together with a fluid influx temperature for each productive layer. Relative production rates and skin factors of the productive layers are calculated from measured fluid influx temperatures and measured first and second bottomhole pressures.

In one method, the permeabilities are obtained by correcting the geometric factor derived from combining the FRA analysis and buildup analysis. In a second method, the permeabilities are obtained by combining the spherical permeability estimated from buildup analysis and the geometric skin factor obtained from history matching the probe-pressure data. In another method, horizontal and vertical permeabilities are determined by analysis of pressure drawdown made with a single probe of circular aperture in a substantially horizontal borehole at two different walls of the borehole.

Method for determination of a fluid influx profile and near-wellbore area parameters comprises measuring a first bottomhole pressure and after operating a well at a constant production rate changing the production rate and measuring a second bottomhole pressure. A wellbore fluid temperature over an upper boundary of a lowest productive layer and wellbore fluid temperatures above and below other productive layers are measured and relative production rates and skin factors of the productive layers are calculated from measured wellbore fluid temperatures and measured first and second bottomhole pressures.

The invention provides an interactive injection-production method of a gas well of a gas storage. The method comprises the following steps that a stratum pressure model is established according to thereal-time radius of a gas reservoir in the gas storage; a well bottom flowing pressure model is established according to the effective permeability and a skin factor of the gas reservoir of the gas storage; and a gas production model for the gas storage is determined according to the stratum pressure model and the well bottom flowing pressure model. The gas production model is obtained via the method, and used to implement gas production on the gas well, peak load shaving can be realized for the gas well timely. Gas supply of the gas well is more reliable and safer, and the gas production cost can be effectively reduced via the method.

Method is directed to determining a fluid influx profile and near-wellbore area parameters in multi-layered reservoirs. A bottomhole pressure in a wellbore is measured. After operation of the wellbore at a constant production rate, the production rate is changed. A bottomhole pressure is measured together with a fluid influx temperature for each productive layer. Graphs of the fluid influx temperature measured as a function of time and of a derivative of this temperature with respect to a logarithm of a time passed after the production rate is changed as a function of time are plotted. Relative production rates and skin factors of the productive layers are calculated based on these graphs.

A method for determining skin factor of a subsurface rock formation from within a wellbore drilled therethrough includes measuring a nuclear magnetic resonance property of the formation at a plurality of lateral depths therein. The measured nuclear magnetic resonance property is used to estimate the skin factor.

Method for determination of a fluid influx profile and near-wellbore area parameters comprises measuring a first bottomhole pressure and after operating a well at a constant production rate changing the production rate and measuring a second bottomhole pressure. A wellbore fluid temperature over an upper boundary of a lowest productive layer and wellbore fluid temperatures above and below other productive layers are measured and relative production rates and skin factors of the productive layers are calculated from measured wellbore fluid temperatures and measured first and second bottomhole pressures.

The invention relates to a coaxial cable for transmitting signals, comprising an inner conductor (302), said inner conductor (302) comprising a conducting layer (400) for conducting a signal The conducting layer (400) of the inner conductor (302) has a thickness that depends on the skin factor of the highest frequency component contained in signals to be transmitted in the coaxial cable (300). The invention also relates to a method for manufacturing said coaxial cable.