120 results about "Formation fluid" patented technology

The invention discloses a high-temperature-resistant and high-pressure-resistant autonomous deep well pressure maintaining sampler, and belongs to the technical field of drilling engineering sampling. The sampler comprises an upper joint, a control outer pipe, an end cover, a valve body and a liquid storage chamber which are connected in sequence, an electromagnet is arranged on the outer side of the end cover; an electric control module is arranged in the control outer pipe; a valve element with a permanent magnet is arranged in the valve body in a sliding mode, the valve element is driven to move axially through non-contact electromagnetic force between the electromagnet and the permanent magnet, and opening and closing of the sampling flow channel are achieved. The bottom of the valve core is provided with a valve core inner channel communicated with the sampling flow channel and the liquid storage chamber and a one-way valve; a sampling inlet channel is formed in the joint of the end cover and the valve body. According to the invention, a pure mechanical sealing-based structure is adopted, so that the sealing reliability and the operation stability in a high-temperature and high-pressure environment of a deep well are remarkably improved, drilling fluid is not needed, and efficient and pressure-maintaining sampling of in-situ formation fluid is realized.

The invention discloses an oil exploitation packer with an expanding type sealing structure, which belongs to the field of oil field downhole tools and comprises a central tube, an upper joint and a lower joint are respectively arranged at two ends of the central tube, a sealing component and a setting component are sequentially sleeved between the upper joint and the lower joint, and the upper joint and the lower joint are connected with a centralizing component and a reversing component in a matched manner. The sealing assembly comprises an installation pipe sleeved on the central pipe and a rubber sleeve sleeved on the outer side of the installation pipe, a first sliding rod and a second sliding rod which are alternately distributed and linked are arranged on the installation pipe in a sliding mode, and a first pushing block and a second pushing block are respectively hinged on the two sliding rods. When the two sliding rods move towards the setting assembly, the first pushing block and the second pushing block alternately penetrate and are spliced into a sealing ring with the outer diameter larger than the inner diameter of the rubber sleeve. The installation pipe provides a stable installation foundation for all the components, sliding rod linkage ensures that the pushing blocks move coordinately and synchronously, the sealing ring extrudes the rubber barrel to enable the rubber barrel to be expanded to be attached to the well wall to achieve sealing, and formation fluid channeling is effectively prevented. And by adjusting the radian of the push block and the length of the push rod, rapid sealing can be achieved under short-distance movement, and sealing reliability and response efficiency are improved.

A system may include a lower completion disposed in a main bore of a multilateral well in a position downhole from a junction of the multilateral well. The system may also include a fluid separator configured to receive formation fluid, which includes oil and water, flowing from the lower completion. The fluid separator may be configured to at least partially separate the formation fluid into formation oil and formation water. The fluid separator may also be configured to output the formation oil, via a separator oil outlet, to flow uphole, and output the formation water, via a separator water outlet, to flow toward a lateral bore of the multilateral well. Further, the system may include a water cut sensor disposed uphole from the fluid separator. The water cut sensor may be configured to measure the percentage of water in the formation oil.

Methods and systems are disclosed herein. A method may include obtaining a well log of a well and obtaining a first fluid sample at a first one of the plurality of depths within the well. The method may include obtaining a second fluid sample at a second one of the plurality of depths within the well. The method may include determining a first fluid property from the first fluid sample and a second fluid property from the second fluid sample. The method may include determining a transform based on the first fluid property, the second fluid property, and the well log data. The method may include applying the transform to the well log data at a third one of the plurality of depths within the well yielding a first predicted fluid property. The method may include determining a subsurface development plan based on the first predicted fluid property.

Disclosed herein are systems and methods to obtain representative formation pore pressure and formation mobility from pressure measurements with a formation testing tool. In some embodiments, the method includes performing a first pre-test in which a pressure sensor measures a drawdown pressure and a buildup pressure, calculating a statistical value for the measured buildup pressure, determining if the statistical value is above or below a threshold, shutting down a mud pulser if the statistical value is above or below the threshold, and performing a second pre-test in which the pressure sensor measures a second drawdown pressure and a second buildup pressure. In embodiments, the second pre-test includes a formation fluid drawdown flow rate that is different than a formation fluid drawdown flow rate in the first pre-test.

The invention belongs to the field of oil production engineering, and discloses a method for analyzing the sand-carrying capacity of a chemical flooding oil well, which comprises the following steps of: on the basis of calculating the viscosity of formation fluid in different stages of a polymer flooding production well, establishing a sand production quantity model of an oil well for producing liquid with the viscosity and a critical sand-carrying particle size model under the output liquid quantity; and judging whether the oil well has sand-carrying capacity or not through sand particle size analysis, sand content calculation and sand burying time of the pump cylinder. The method has high field applicability, can predict whether the chemical flooding production well can carry sand to produce oil or not in advance in the oil reservoir deployment stage, clearly determines which sand prevention and sand carrying lifting process mode is adopted, provides theoretical guidance for oil production engineering block scheme design, and improves the oil production efficiency. And meanwhile, technical support is provided for adjustment of a single-well sand prevention and sand carrying lifting process in different production and polymer concentration stages of the converted chemical flooding production well.

The present application relates to a kind of high temperature high pressure formation fluid containing large hole fracture plugging simulation device, including nitrogen bottle, liquid storage tank, simulation wellbore, heating insulation cover, back pressure valve and hole fracture isolation plate, there is inner cylinder in upper kettle body, there is simulation leakage layer in inner cylinder, upper kettle body and lower kettle body are connected by flange, hole fracture isolation plate is set between upper kettle body and lower kettle body, back pressure valve is set at the place close to hole fracture isolation plate of lower kettle body, heating insulation cover is set on the outer wall of upper kettle body and lower kettle body.The simulation method for high temperature high pressure formation fluid containing large hole fracture plugging using the above device, including: plugging slurry is discharged or passed through formation fluid and then enters simulation leakage layer;The plugging effect of conventional drilling fluid on small hole fracture leakage layer is judged by the pressure difference of upper kettle body and lower kettle body;The breakthrough pressure of sealing zone is obtained by the pressure difference between upper kettle body and lower kettle body after sealing zone is formed by solidified cementation type plugging slurry.The present application is in line with actual downhole, easy and fast to operate, provides platform and means for the plugging research of formation fluid containing large hole fracture leakage layer.

The invention discloses a natural gas hydrate reservoir in-situ fluid sampling device and method, and relates to the technical field of natural gas exploitation. The pumping module is used as a driving device for pumping formation fluid; the double-packer module comprises an upper packer and a lower packer, a sealed test interval is formed between the upper packer and the lower packer, and a pipeline connected with the pumping module penetrates through the upper packer to reach the test interval and is connected with a probe; the probe is used for penetrating out of a test interval to extract formation fluid; a lower packer, an upper packer and a pumping module are sequentially arranged from bottom to top from the bottom of the well; the in-situ fluid identification and sampling module comprises a PVT sampling barrel and a resistivity sensor; and the PVT sampling barrel and the resistivity sensor are connected to the pipeline between the upper packer and the pumping module and penetrate through the wall of the pipeline so as to measure the formation fluid extracted from the pipeline. The in-situ fluid under the original condition can be collected.

The invention relates to the technical field of material permeability experiment devices, in particular to a microscopic seepage model simulation device which comprises a clamping assembly, a box body with an upward opening and an upper gland with a transparent observation window in the middle. The device is reasonable and compact in structure and convenient to use, sandstone particles can be compressed in the simulation bin through the upper gland, and a simulated sandstone layer with the same structure as an oil reservoir stratum sandstone is formed; the seepage liquid can more uniformly enter the vertical micropores in the rectification strip through the left diversion trench, and the horizontal micropores communicated with the vertical micropores can enable the seepage liquid to uniformly flow into the simulation bin from the right side surface of the rectification strip in a layered manner, so that the seepage liquid can flow in parallel in the simulative sandstone layer; therefore, the seepage liquid can simulate one-dimensional linear flow in the simulated sandstone layer, the situation that the seepage liquid has excessive turbulent flow to influence an experiment result is avoided, the flowing state of deep stratum fluid laminar flow can be simulated more truly, and a better experiment result is obtained.

The application discloses a formation fluid identification method, comprising the following steps: acquiring first infrared spectrum data and second infrared spectrum data of a formation section to be interpreted; performing curve fitting on the first infrared spectrum data to obtain a fitting curve, determining a first factor according to an extreme value of a first wavelength section of the fitting curve, determining a second factor according to an opening and area integral of the fitting curve, and determining a third factor according to a center of a second wavelength section of the fitting curve; calculating a standard deviation curve of a standard deviation of longitudinal absorption at all wavelengths of a same depth point according to the second infrared spectrum data, and calculating a peak tailing factor of the standard deviation curve; and determining a type of the formation section according to the first factor, the second factor, the third factor and the peak tailing factor. The application further discloses a system, a computer device and a readable storage medium.

The present application belongs to the field of oilfield shale gas exploration and development experiment, and particularly relates to a shale gas quantity testing method. The present application constructs the basic formation condition corresponding to the shale sample by placing the shale sample into a set testing environment, and tests the lost gas quantity by simulating the drilling core lowering temperature and pressure process according to the actual situation of the related parameters in the process of drilling core taking, so that the testing environment of the lost gas quantity is more consistent with the actual situation when drilling core is taken, thus the large error generated by theoretical analysis can be avoided, and the accuracy of the testing result of the lost gas quantity is effectively improved. Furthermore, the shale sample is restored to the temperature and pressure conditions of the reservoir by adjusting the formation fluid, temperature and pressure, so that the shale is fully saturated and adsorbs the simulated formation fluid, thereby the basic formation condition corresponding to the shale sample which is more consistent with the actual formation condition is constructed, and is used for testing the shale gas quantity, so as to ensure the accuracy of the shale gas quantity testing.

The downhole dynamic thermal field control method and apparatus provided in this application include: acquiring initial temperature field data of the target downhole wellbore and a pre-constructed formation fluid coupling model, and calculating the first total energy supply power of each heating section of the target downhole based on these data; segmenting and heating each heating section of the target downhole according to the first total energy supply power, and acquiring the first real-time temperature data of each heating section of the target downhole; determining the corresponding first downhole thermal field uniformity based on the first real-time temperature data, and determining the thermal field control state based on the uniformity and the first real-time temperature data; if the thermal field control state is a stable and compliant state, maintaining the first total energy supply power of each heating section of the target downhole; if the thermal field control state is a state to be adjusted, adjusting the first total energy supply power to obtain the adjusted second total energy supply power; thereby improving the accuracy of downhole dynamic thermal field control and enhancing the real-time matching capability between energy supply and formation heat demand.

The utility model discloses a rock core experiment device for simulating oil reservoir environment, which comprises an oil reservoir simulation device, the oil reservoir simulation device comprises a rock core cabin body, a rock core cabin opening is arranged on the top wall of the rock core cabin body, the rock core cabin body is connected with a pressure regulating device, and a rock core base is arranged on the bottom wall in the rock core cabin body. And the core base is in the projection of the core cabin opening. The oil reservoir simulation device can provide temperature, pressure and formation fluid, simulate the real consolidation condition and performance characteristics of the artificial rock core in the formation environment, truly reflect the characteristics of the artificial rock core in the formation environment, provide more real experimental data for sand prevention design, preferably select better products, and improve the production efficiency. The sand prevention effect of chemical sand prevention is improved, and the sand prevention validity period is prolonged.

The application discloses a kind of formation fluid sampling device's use method, solve the technical problem that manual control valve cannot detect, sampling success rate is difficult to guarantee.The formation fluid sampling device includes sample cylinder body, energy storage mechanism, sampling connector, sampling channel, sampling interface and manual control valve, further includes: inspection port, is set on sampling connector, and with sampling channel communication;Inspection plug, is screw-connected in inspection port;Pressure relief port, is set on sampling connector, and with sampling channel communication;Pressure relief valve, is screw-connected in pressure relief port;First check valve, is set in sampling channel, and is located between sampling interface and pressure relief valve, manual control valve is between inspection port and pressure relief port.The application can realize the detection of manual control valve, also can prevent sample liquid from flowing out of sampling device, improve the use reliability of sampling device, guarantee sampling success rate.

This invention discloses an oil-water-gas well reservoir expansion and sealing jet fluid production and sand removal device, relating to the field of oil production technology. The device includes a central tube and further comprises: an expansion assembly located around the central tube, with its lower end positioned on the central tube and its upper end capable of sliding on the central tube, used for radial expansion under the drive of a hydrodynamic fluid; and a jet nozzle located below the central tube and below the expansion assembly, used to spray hydrodynamic fluid, creating a negative pressure zone in the spray area to absorb formation fluid. This integrated design combines the expansion assembly and the jet nozzle, allowing for the completion of both annular sealing and jet fluid production and sand removal functions in a single well run, avoiding the cumbersome process of two well runs required by traditional technologies and shortening the operation time.

The present application relates to the technical field of well testing analysis, and is a high-temperature and high-pressure deep well perforation early formation fluid property prediction method. The method is performed according to the following steps: establishing a fitting equation of the maximum value of the average density of the downhole mixture of the early production test of the high-temperature and high-pressure deep well of the tested oil in the research area and the static pressure gradient at the perforation section after the normal production test of the high-temperature and high-pressure deep well of the tested oil; establishing a corresponding relationship table of the static pressure gradient T at the perforation section of the high-temperature and high-pressure deep well and the formation fluid property; and obtaining the predicted formation fluid property of the to-be-evaluated oil well from the maximum value of the average density of the downhole mixture of the early production test of the to-be-evaluated oil well. The present application provides a high-temperature and high-pressure deep well perforation early formation fluid property prediction method, fills the blank of the high-temperature and high-pressure deep well perforation early fluid property prediction technology, and has the characteristics of simplicity, high efficiency, low cost, and high accuracy.

This invention provides an experimental apparatus and method for simulating the phase state of fluids in oil and gas reservoirs, belonging to the field of experimental technology for fluid phase state in oil and gas field development. It includes: a support frame with a first cavity, a second cavity, and a third cavity arranged from top to bottom; a pressure regulating mechanism for adjusting pressure is installed in the second and third cavities; the first cavity is connected to the second cavity via a first pipe and a second pipe, and the first cavity is connected to the third cavity via a third pipe; the second cavity is connected to the third cavity via a fourth pipe; an output pipe is located at the top of the first cavity, with the inlet of the output pipe located inside the first cavity and lower than the opening of the first pipe on the first cavity; valves for controlling the opening and closing of the output pipe, the first pipe, the second pipe, the third pipe, and the fourth pipe are all installed. This invention has a simple structure, is easy to use, and can accurately simulate the depletion development process of oil-bottom-water type oil and gas reservoirs in upper gas formations, clearly defining the phase change characteristics of formation fluids.

The invention discloses an underground fluid in-situ sampling system and method, and belongs to the technical field of underground fluid sampling. The device comprises a sampling valve body, an air pressure driving assembly and a sample receiving assembly, the sampling valve body comprises a valve body, a three-way cavity formed in the valve body and a first one-way valve, the first one-way valve is arranged in a first hole channel of the three-way cavity, and the first one-way valve can be opened by external pressure; the air pressure driving assembly comprises an air supply pipe used for supplying pressurized and compressed air, and the air supply pipe is communicated with the second hole channel of the three-way cavity. The sample receiving assembly comprises a sampling pipe, one end of the sampling pipe is communicated with the third hole channel of the three-way cavity, and the other end of the sampling pipe can output fresh formation fluid. The device can be suitable for long-term deployment in a limited space, and the original state of fluid is kept to the maximum extent.

This invention discloses a high-temperature, high-pressure self-contained deep well sampling device, belonging to the field of drilling engineering sampling technology. The sampling device includes an upper connector, a control outer pipe, an end cap, a valve body, and a storage chamber connected in sequence. An electromagnet is installed on the outside of the end cap, and an electrical control module is installed inside the control outer pipe. A valve core with a permanent magnet is slidably installed inside the valve body. The valve core is driven axially by the non-contact electromagnetic force between the electromagnet and the permanent magnet, realizing the opening and closing of the sampling channel. The bottom of the valve core has an internal channel connecting the sampling channel and the storage chamber, as well as a one-way valve. A sampling inlet channel is opened at the connection between the end cap and the valve body. This invention adopts a structure mainly based on pure mechanical seals, significantly improving the sealing reliability and operational stability under the high-temperature and high-pressure environment of deep wells. It does not rely on drilling fluid and achieves efficient, pressure-maintained sampling of in-situ formation fluids.

The application relates to an intermittent pumping sampling method for a low-permeability reservoir, which comprises the following steps: calculating the lower limit of the formation mobility of continuous pumping sampling of an ultra-low-permeability reservoir; when the mobility is less than the lower limit of the formation mobility of continuous pumping sampling, intermittent pumping is carried out; the breakthrough volume of the formation fluid is obtained, and the original invasion depth of drilling fluid is obtained through simulation inversion; according to experimental data, the initial invasion speed of mud filtrate under different original invasion depths is obtained, and the upper limit of the continuous invasion speed of mud filtrate in the pumping sampling process is determined; the numerical simulation of the key factors of intermittent pumping is carried out, intermittent pumping operation schemes under different conditions and the total operation time of the corresponding operation schemes are obtained; the optimal pressure recovery ratio is determined; the intermittent pumping operation scheme under the continuous invasion speed of mud filtrate and the optimal pressure recovery ratio and the total operation time of the operation scheme are obtained. The scheme can solve the sampling problem of the ultra-low-permeability reservoir and improve the success rate of sampling.

The application provides a gradient chemical sand control process method based on weakly cemented reservoir skeleton stability, which comprises the following steps: step 1, obtaining the parameters of a sanding well formation and formation fluid when sanding; step 2, selecting a reservoir middle depth as a horizontal tangent line and taking points X1-X N , calculating the reservoir formation pressure distribution of different crude oil viscosities and different shale contents; step 3, calculating the corresponding pressure gradient of X1-X N ; step 4, drawing a reservoir sanding pressure gradient curve diagram when the oil well sands; step 5, testing the strength of an anti-swelling sand stabilizer material by using a laboratory experiment; and step 6, determining the applicable limits of the near-well long-acting sand consolidation and the far-well anti-swelling sand stabilization method of a sanding well with different crude oil viscosities and different shale contents. The gradient chemical sand control process method based on weakly cemented reservoir skeleton stability utilizes the idea of "far-well anti-swelling sand stabilization + near-well long-acting sand consolidation", reduces the large use of a single sand control agent, and reduces the use cost of the sand control agent.

The invention discloses a method for calculating the maximum safe injection pressure of geological storage of carbon dioxide in a deep saline water layer, which comprises the following steps of: establishing a three-dimensional geomechanical model; the output parameters are overlying stress distribution and maximum horizontal principal stress distribution of a three-dimensional stress field under the initial formation fluid pressure field and minimum horizontal principal stress distribution under the initial formation fluid pressure field; gradually increasing the initial formation fluid pressure field to pressure fields of a plurality of simulation working conditions, and respectively obtaining minimum horizontal principal stress distribution and overburden stress distribution under the pressure fields of the plurality of simulation working conditions; determining the fracturing critical pressure of the cap layer; determining the activation pressure of a target fault at the cover layer; and determining the maximum safe injection pressure of the geological storage of the carbon dioxide in the deep saline water layer according to the critical pressure of fracture of the cover layer and the activation pressure of the target fault at the cover layer.

A production inlet assembly for use within a subterranean wellbore. The production inlet assembly includes a landing sub that affixable within the wellbore, and a sand catcher including a chamber that is configured to receive particulates separated from formation fluids that enter the production inlet assembly. The production inlet assembly also includes a telescoping joint coupled between the landing sub and the sand catcher that is permitted to translate axially along the landing sub.

The application discloses a kind of oil reservoir gas drive fine delineation and gas channeling prevention and control method based on facies belt division.The method of the application can be used for the "fine" description of formation fluid migration in the process of CO2 injection development, through long core displacement, interface tension determination is combined, and well stream component is determined, the distribution of each facies zone in the ground is obtained through numerical simulation, accurate gas channeling early warning can be realized, and the starting pressure gradient at different development moments can be obtained in combination with the determined starting pressure gradient;The carbonized water is prepared by generating and breaking CO2 micro-bubbles in the application, and the enhanced CO2 micro-bubbles are generated by using the carbonized water and CO2, which can avoid the influence of water lock effect, improve the stability of micro-bubbles, better play the plugging and profile control effect, and improve the oil displacement efficiency, for the treatment of gas channeling, which is helpful to further improve the recovery efficiency and CO2 storage effect.

This invention relates to a flow pressure regulating device for drilling wellbore, comprising an isolation plate, a linkage assembly, a driven assembly, and an regulating assembly. The isolation plate has a through-cavity in its center, which seals and connects two adjacent drill pipes. The outer edge of the isolation plate, specifically the outer edge portion, seals the outer wall of the drill pipes via a sealing ring, thus preventing the formation of annulus between the drill pipes and the well wall. The isolation plate has a through-hole communicating with the annulus. During drilling, the flow of drilling fluid drives the linkage blades to rotate within the inner cavity. When the flow pressure in the annulus of a certain well section exceeds the safe range compared to the formation fluid pressure of the well section, the operator can remotely control the controller via a remote control device to rotate the linkage blades, thereby adjusting the inclination angle of the linkage blades. This device has the advantage of being able to regulate the flow pressure in the annulus of the wellbore.

Methods and systems are disclosed herein. A method may include operating a closed-loop geothermal system (100) disposed in a well (101). The well (101) includes a wellbore (102) penetrating the geothermal heat source (104), a casing string (120), a control valve (125), and a temperature sensor (127). An annulus (107) is formed between the closed-loop geothermal system (100) and the casing string (120). The method includes measuring, using the temperature sensor (127) a first temperature of the geothermal fluid. The method includes opening, when the first temperature is lower than a first predetermined temperature, the control valve (125) in order to discharge geothermal fluid from the annulus (107).

The invention relates to the technical field of formation fluid exploitation, in particular to a test parameter regulation and control method of a formation test lifting device and the formation test lifting device.The test parameter regulation and control method comprises the steps that A, the pump pressure of a power liquid pump is set; s101, pressure distribution of return liquid from a return liquid outlet of the jet pump to an upper port of the first annulus is calculated, and whether the pressure of the return liquid at the upper port of the first annulus is not smaller than 0 or not is judged; s102, when the return liquid pressure of the upper port of the first annulus is smaller than 0, the pump pressure of a power liquid pump is set, and the step S101 and the step S102 are executed; and when the return liquid pressure of the upper port of the first annulus is not smaller than 0, the final pump pressure of the power liquid pump is output. The final pumping pressure Pinj is output under the condition that the return liquid pressure of the upper port of the first annulus 104 is not smaller than 0, it is ensured that the formation fluid can be stably conveyed to the ground, and the formation fluid yield testing accuracy is improved.

The invention provides an evaluation method for improving CO2 geological sequestration site screening and sequestration safety, and the method comprises the steps: obtaining a region plane structure map, a formation pore pressure gradient and a formation temperature gradient of a target layer through the analysis of geological data, and obtaining the pore pressure plane graphs and the formation temperature plane graphs of different target layers through calculation; and calculating a CO2 density plane graph and a CO2 solubility plane graph of different layers in combination with a formation fluid mineralization degree graph. On the basis, a CO2 geological sequestration capacity plane graph and a CO2 geological sequestration dissolution capacity plane graph can be calculated by combining a reservoir physical property plane graph and a CO2 sequestration coefficient. And then, according to the CO2 density map and the reservoir physical property map, a CO2 reinjection formation pressure change map is rapidly calculated. And an element superposition method is adopted to be combined with all the calculated elements, so that the region-level CO2 geological sequestration site comprehensive dessert plane graph can be obtained. According to the analysis method disclosed by the invention, rapid, efficient and quantitative CO2 site screening is ensured, and the limitation and subjectivity of the prior art are changed.

A method for determining a porosity log of a log type for a hydrocarbon reservoir, including: obtaining an input core image, a formation bulk log of the log type, and a formation fluid log of the log type for the reservoir; determining, using a segmentation model and the input core image, a segmented core image to delineate a distribution along the reservoir; determining, using the segmented core image, a volumetric log for the reservoir: determining, using the volumetric log and a variable rock matrix value of the log type, a rock matrix log of the log type by assigning the variable rock matrix value of the log type to a lithology or mineralogy; and determining, using the rock matrix log, the formation bulk log of the log type, and the formation fluid log of the log type, the porosity log of the log type for the reservoir.

The invention provides a rapid method for evaluating the yield increasing effect and economical efficiency of underground electric heating of a horizontal well, and belongs to the technical field of oil and gas field development. Comprising the following steps that geological reservoir parameters of a target oil field, thermophysical parameters of rock fluid, temperature and pressure monitoring data and oil well parameters of a target oil well are collected; improving a horizontal shaft-oil reservoir heat transfer simulation device; determining the influence of oil reservoir fluid parameters and oil well parameters on the heating condition; carrying out sensitivity analysis on oil reservoir fluid parameters and oil well parameters which influence the heating condition; respectively establishing two-dimensional curve charts of the relationship between the influence parameters and the oil increase percentage and the relationship between the influence parameters and the input-output ratio; and determining the underground electric heating yield increasing effect and economical efficiency evaluation indexes of the horizontal well. According to the method, based on the formation temperature and pressure conditions and the reservoir temperature distribution rule of horizontal well underground electric heating in the formation liquid supply state, the influence of different factors on the oil increasing percentage and the input-output ratio before and after electric heating is considered, and an important basis is provided for productivity prediction and effect evaluation of horizontal well underground electric heating.