8 results about "Volume factor" patented technology

The application discloses a method for determining hydrocarbon saturation of a logging reservoir and related equipment, and relates to the field of oil and gas exploration. The method comprises the following steps: obtaining gas logging data and logging porosity data; obtaining natural gas volume and gas-oil ratio data under surface conditions based on the gas logging data, wherein the gas-oil volume ratio data comprises gas volume coefficient, crude oil volume coefficient, gas-oil ratio, and gas-oil ratio when the formation pressure is the bubble point pressure; the reservoir hydrocarbon saturation comprises at least one of gas saturation, oil saturation and total hydrocarbon saturation; calculating oil and gas property parameters under surface conditions; calculating oil and gas property parameters under reservoir conditions based on formation temperature and pressure conditions; judging the saturation state of the reservoir based on the bubble point line temperature and pressure conditions, and judging the oil and gas reservoir saturation state according to the formation pressure and the reservoir bubble point pressure, wherein the oil and gas saturation state comprises liquid hydrocarbon single-phase state, gaseous hydrocarbon single-phase state and oil-gas mixed-phase state; and obtaining the reservoir hydrocarbon saturation based on the reservoir saturation state, the natural gas volume under the surface conditions, the logging porosity data and the gas-oil volume ratio data.

The application discloses a kind of Jurassic system reservoir control bottom water invasion profile control process selection method, comprising the following steps: S1, first, the cumulative oil production of reservoir, cumulative water production, cumulative injection, geological reserves, crude oil volume coefficient, formation water volume coefficient, comprehensive compression coefficient, crude oil original volume coefficient, formation original pressure and current reservoir pressure data are collected, then the data collected is used to calculate the water invasion amount of block in past years, and curve is drawn;S2, according to the water invasion amount of block in past years and water invasion amount curve trend, select profile control process;S3, according to the profile control process selected in step S2, the well group that needs profile control of Jurassic bottom water reservoir is profile controlled.The application calculates and characterizes the bottom water invasion condition of Jurassic system reservoir, calculates the different states of bottom water reservoir water invasion, and selects different profile control processes according to the different states of bottom water reservoir water invasion, so as to realize the purpose of controlling bottom water invasion and inhibiting water content.

The present application relates to a high-precision calculation method for the original volume coefficient of shale gas in a complex area based on gridding, and the technical scheme comprises the following steps: step one: gridding the top / bottom surface structure map and the ground elevation map of shale; step two: calculating the middle buried depth map of the shale gas reservoir by curved surface operation; step three: calculating the formation temperature and the formation pressure; step four: calculating the pseudo-contrast temperature and the pseudo-contrast pressure; step five: calculating the deviation coefficient; and step six: calculating the volume coefficient.

The application provides a method and system for determining condensate oil content in a condensate gas reservoir. The method for determining condensate oil content in the condensate gas reservoir comprises the following steps: determining condensate oil reserves according to ground cumulative condensate oil collection amount, condensate oil original geological reserves and formation released condensate oil quality; determining condensate gas volume coefficient, condensate gas reservoir pore volume, condensate gas reservoir saturation parameter and condensate gas reservoir water vapor content; determining condensate oil content according to condensate oil reserves, condensate gas volume coefficient, condensate gas reservoir pore volume, condensate gas reservoir saturation parameter and condensate gas reservoir water vapor content. The application can conveniently and quickly determine condensate oil content in the condensate gas reservoir, and provides technical support for development of the condensate gas reservoir.

The present application relates to the field of gas reservoir development, and discloses a method for determining free gas saturation and gas content proportion of deep coalbed methane, which comprises the following steps: obtaining basic parameters of deep coal reservoir, determining theoretical ton coal adsorption capacity, ton coal non-adsorbed gas content, cubic coal non-adsorbed gas content, coalbed methane dissolution coefficient, gas volume coefficient and cubic coal maximum dissolved gas content according to the basic parameters, and then determining free gas saturation, and finally determining the percentage of adsorbed gas, dissolved gas and free gas by using the free gas saturation. The method can effectively determine and evaluate the free gas saturation of deep coalbed methane and the gas content proportion in different occurrence states, and the required parameters are less and easy to obtain and operate. In addition, the method is suitable for coal reservoirs with all structural characteristics and has good practicability.

A method and system for downhole measurements of reservoir temperature and pressure and reservoir fluid compressibility, density, viscosity, and bubble point pressure to obtain an oil formation volume factor (FVF) or a gas to oil ratio (GOR) in real time are disclosed. In embodiments, methods include conveying a downhole formation analysis tool into a wellbore, measuring reservoir fluid compressibility, density, viscosity, and bubble point pressure, and obtaining the oil formation volume factor (FVF) or the gas to oil ratio (GOR) while the fluid sampling tool is still in the wellbore.

The invention discloses a method for determining a formation water volume coefficient, and belongs to the field of geothermal exploration and development and oil and gas reservoir exploration and development. According to the technical scheme, the ground temperature and pressure of a target layer are obtained, formation water and dissolved gas are extracted, and stable water production, gas production and cumulant are obtained; calculating the gas-water ratio according to the yield, and sampling at a wellhead to measure formation water and gas density and water salinity; calculating the stratum water density by combining the ground temperature pressure, the density and the mineralization degree; and establishing a new equation to calculate the formation water volume coefficient according to the definition of the gas-water ratio, the density and the formation water volume coefficient. The method has the beneficial effects that the sampling analysis cost of the formation water of the evaluation unit is reduced, the calculated formation water volume coefficient can meet the precision requirements of water resource evaluation and oil and gas reservoir development test modeling, the calculation precision of the formation water volume coefficient is effectively improved, the universality and practicability of the method are enhanced, and efficient development and utilization of resources are promoted.

This application provides a method and apparatus for predicting the dynamic reserve utilization degree of an oil reservoir. The method for predicting the dynamic reserve utilization degree includes: acquiring formation pressure, surface crude oil density, natural gas relative density, and production gas-oil ratio measured during oil production; determining the crude oil volume factor under the original formation pressure based on the formation pressure, surface crude oil density, natural gas relative density, and production gas-oil ratio; determining the real-time crude oil volume factor during oil production based on the crude oil volume factor under the original formation pressure; and determining the dynamic reserves of the oil reservoir based on the crude oil volume factor under the original formation pressure, the real-time crude oil volume factor, and the corresponding comprehensive compressibility coefficient of the reservoir. The method for predicting the reserve utilization degree includes: acquiring the dynamic reserves of the oil reservoir; acquiring the static reserves of the oil reservoir; and predicting the reservoir reserve utilization degree based on the dynamic reserves and the static reserves. This method aims to achieve the effect of predicting the dynamic reserves and utilization degree of an oil reservoir.