The invention provides a visualization experiment device for bearing coal fracture observation and gas seepage. The problem that a nontransparent experiment device cannot meet the experiment requirement can be solved. The visualization experiment device comprises a transparent tempered glass; the transparent tempered glass is arranged on a base; a pressure chamber is arranged between the transparent tempered glass and the base; the pressure chamber is connected with a first valve, a first pressure gauge and a confining pressure air-feeding device in turn through a pipeline; the pressure chamber is communicated with a second valve through the pipeline; a transparent heat shrinking pipe is arranged in the pressure chamber; a test piece is arranged in the transparent heat shrinking pipe; an upper rock core plug is matched with the upper part of the transparent heat shrinking pipe; the upper rock core plug is connected with a piston rod; the piston rod passes through the transparent tempered glass; a sealing rubber ring is arranged between the piston rod and the transparent tempered glass; the piston rod is connected with a loading cylinder; the loading cylinder is connected with hydraulic oil. According to the invention, a coal test piece is wrapped by the transparent tempered glass and the transparent heat shrinking pipe and the pressure chamber is supplied with pressure by air, so that the image observation for crack extension is not affected and a microscopy camera is adopted for ream-time dynamic monitoring.

Visualization experiment device for bearing coal fracture observation and gas seepage

The invention discloses a dynamic prediction method for wellbore flow in a coal-bed gas well. The dynamic prediction method comprises following steps: sampling liquid in a wellbore oil pipe in order to acquire real solid content of a wellbore; judging the flow pattern of gas-liquid-solid three phase flow in the wellbore and determining modeling parameters for the gas-liquid-solid three phase flow; establishing a gas-liquid-solid three phase flow pressure model in the wellbore based on the real solid content and the modeling parameters in combination with the position of the working fluid level and data of well body configuration; establishing a temperature distribution model based on the gas-liquid-solid three phase flow pressure model, the real solid content and the modeling parameters by combining with heat transfer parameters of a well body; and obtaining distribution results of pressure and temperature of gas-liquid-solid three phase flow pressure in the wellbore along the depth of the wellbore based on the pressure model and the temperature distribution model. The dynamic prediction method for wellbore flow in the coal-bed gas well has the capability of predicting flow state, flow rate, pressure and temperature distribution and other physical property parameters at any position in the wellbore based on liquid production capacity and gas production capacity of a wellhead, casing pressure and other physical property parameters.

Dynamic prediction method for wellbore flow in coal-bed gas well

The invention discloses a method for predicting generation of hydrate in a nature gas pipeline, and belongs to the technical field of oil-gas storage and transportation engineering. With the continuous development of Chinese economy, the consumption demand of people for natural gas is continuously increased. The technique for transporting the natural gas needs to be continuously promoted in the industrial field, but natural gas hydrate formed in the process of transporting the natural gas through pipelines is important obstruction for restricting the development of the natural gas transportation technique. The method disclosed by the invention solves the problem that selecting a pipeline position is blind when the natural gas hydrate is disposed in the past engineering. The starting point of the hydrate generated in the pipeline is found out by analyzing the pressure and the temperature of a discretionary point of the pipeline, synthetizing a pressure-temperature curve of the pipeline and contrasting the pressure-temperature curve of the pipeline and a phase equilibrium curve of the hydrate. Through adoption of the method disclosed by the invention, the place in which the hydrate is generated in the natural gas transportation pipeline can be disposed in a targeted manner, so that the use quantity of natural gas hydrate inhibitors is reduced.

Method for predicting generation of hydrate in nature gas pipeline

The invention discloses an oil pipe corrosion degree forecasting method and device, and belongs to the technical field of oilfield downholes. The method includes the steps: S1, selecting at least two groups of downhole working condition data and actual oil pipe corrosion rate data corresponding to the downhole working condition data, normalizing the selected data, and dividing the normalized data into a training data sample and an inspection data sample; S2, modeling the training data sample by combining a fuzzy linear regression method with a least square method to obtain an oil pipe corrosion forecasting model taking the downhole working condition data as dependent variables and taking forecasted oil pipe corrosion rate data as variables; S3, verifying correctness of the oil pipe corrosion forecasting model by the aid of the inspection data sample, executing S4 if the model passes inspection, otherwise, transposing S1, and selecting new data to repeatedly execute processes; S4, forecasting the corrosion degree of in-service oil pipes in a designated environment by the aid of the obtained oil pipe corrosion forecasting model. By the aid of the oil pipe corrosion degree forecasting method and device, forecasting accuracy of the corrosion degree of downhole oil pipes can be improved.

Oil pipe corrosion degree forecasting method and device

The invention provides a high-acidity gas field wellbore string material optimization evaluation system and method, and belongs to the field of high-acidity gas field development. The high-acidity gas field wellbore string material optimization evaluation system includes a corrosion rate prediction model and a stress corrosion cracking boundary model; the corrosion rate prediction model includes H2S partial pressure-temperature, H2S partial pressure-CO2 partial pressure and elementary substance S-pH value corrosion rate prediction drawing boards; the stress corrosion cracking boundary model includes a failure boundary of a material under conditions of the temperature and the H2S partial pressure and a failure boundary of the material after sulfur is separated out under the conditions of the temperature and the H2S partial pressure. The system and the method solve the problems that due to a corrosion simulation evaluation method and a corrosion prediction model and software, a gas field highly containing H2S/CO2 is lack of basis on material selection, and provide a theoretical support for high-acidity gas field development and safety production.

High-acidity gas field wellbore string material optimization evaluation system and method

System for monitoring components of shaft fluid of H2S/CO2-containing gas field and analysis method thereof

The invention provides an oilfield development plugging agent which is prepared from unsaturated resin emulsion, a curing agent and a coupling agent as raw materials, the unsaturated resin emulsion is formed by mixing 196 unsaturated polyester resin, an emulsifier and water, and the coupling agent is gamma-aminopropyl triethoxysilane. The plugging agent is suitable for the formation at the temperature of 30-90 DEG C, and the resin solution can be self curing at the temperature, and can be used for the permanent sealing of large holes or large cracks which do not need plugging releasing. The oilfield development plugging agent has strong plugging ability, salt resistance, wide applicable scope, long validity period and low cost. Compared with the blocking agent in other profile control systems, the oilfield development plugging agent has obvious advantages on plugging of oil reservoirs with large holes or large cracks, and is in line with the needs of oil field sites.

Oilfield development plugging agent

The invention provides a CO2 flooding extraction well shaft flow state determining and parameter optimizing method, and belongs to the field of reservoir mining. The method comprises the following steps that (1) production performance simulation of a CO2 flooding extraction well is conducted to obtain the production performance of the CO2 flooding extraction well and the distribution rules, along a shaft, of the pressure, the temperature, the density and the viscosity of the injection shaft; (2) the distribution rules, along the shaft, of the pressure and the temperature of the CO2 flooding extraction well are drawn on a CO2 phase diagram, a pressure distribution diagram and a temperature distribution diagram of the CO2 flooding extraction well shaft are obtained, and therefore CO2 phase states at different positions along the shaft can be directly searched out in the diagrams; (3) production parameters are selected preferably, wherein production data are changed on the premise that structural data of a well body are not changed, then the step (1) and the step (2) are repeated, and an optimal production technology and an optimal working system are selected preferably according to site requirements. By means of the CO2 flooding extraction well shaft flow state determining and parameter optimizing method, production performance simulation and analysis of CO2 flooding production wells are realized.

CO2 flooding extraction well shaft flow state determining and parameter optimizing method

The invention provides an underground upgrading viscosity-reducing oil production method for thick oil. The underground upgrading viscosity-reducing oil production method for the thick oil comprises the steps that in the process of steam injection production of the thick oil, amphiphilic catalysts and additives are injected into a stratum along with steam, an oil layer is heated to enable the temperature to range from 160 DEG C to 240 DEG C, and soaking operation is conducted for 1-5 days, so that an aquathermolysis reaction between asphaltene and colloid in heavy components of the thick oil is facilitated, wherein the total mass of the amphiphilic catalysts and the additives is 0.15-2.0wt% the mass of the thick oil, the amphiphilic catalysts are prepared through a reaction between nickel salt and aromatic ring acid, and the additives are hydrogen donors and/or dispersing agents. According to the invention, the amphiphilic catalysts are hydrophilic and oleophilic, dissolve and disperse in the steam, and then disperse in the thick oil of the stratum along with the steam. Under the existing steam injection condition, the amphiphilic catalysts are added to the steam, and site operation can be conducted. The underground upgrading viscosity-reducing oil production method for the thick oil is easy to operate, and safe and reliable, and has the broad application prospect and the high promotion value, the production cycle is remarkably prolonged, and the good effect of enhanced production of the oil can be achieved.

Underground upgrading viscosity-reducing oil production method for thick oil

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