120 results about "Reservoir heterogeneity" patented technology

A system and method identify hydrocarbon productive reservoir zones using Monte Carlo numerical analysis to account for uncertainties in log measurements and petrophysical parameters. Random errors in logging tool responses and core measurements, as well as reservoir heterogeneity, are incorporated in a Monte Carlo simulation to output appropriate petrophysical models to calculate statistical distributions for saturation and permeability to define productive zones, non-productive zones and zones of undetermined productivity as a basis of deciding whether additional logging, core sampling or well test data are needed to reclassify the undetermined zones as either productive or non-productive. As uncertainties are quantified in the analysis, the degree of certainty in determining productive and non-productive zones is known and can be used to decide whether to further test, stimulate or abandon reservoir zones.

The invention discloses a reservoir heterogeneity characterization method under a regular development well pattern of horizontal wells. The method mainly comprises steps as follows: establishing a research area construction model to construct a target stratum model; (2) performing simulation to obtain a lithological model based on the stratum model established in Step (2); establishing a reservoir permeability 3D model in sandstone in the lithological model established in Step (3); establishing a virtual vertical well at the wellhead of each horizontal well; extracting stratum hierarchical data and permeability curves of each virtual vertical well; calculating the permeability heterogeneity parameter of a target interval of each well by using vertical well permeability curves in actual drilling and the permeability curves of the virtual vertical wells obtained in Step (6); drawing permeability heterogeneity parameter plane contour line maps to represent heterogeneity characteristics of reservoirs. A more accurate method is provided for carrying out reservoir heterogeneity characterization for oil fields exploited with horizontal wells as the main means.

The invention discloses a blocking remover for hypotonic inhomogeneous sandstone reservoir and a using method of the blocking remover. The blocking remover comprises an agent A, an agent B and an agent C, wherein the agent A consists of the following components in percentage by weight: 10%-25% of oxidant, 8%-12% of activator and the balance of water; the agent B consists of 10%-15% of a reducing agent, 0.3%-1.2% of a foaming agent, 0.3%-0.6% of a foam stabilizer, and the balance of water; the agent C consists of 8%-12% of HCL, 6%-10% of organic acid, 2%-5% of NH4HF2, 0.5%-1.5% of a corrosion inhibitor, 0.5%-1.5% of an iron ion stabilizer and the balance of water. The using method comprises the steps of step one, preparing the agent A, the agent B and the agent C; and step two, injecting the agent A into a ground layer by a pipeline, then injecting the agent B into the ground layer, and finally injecting the agent C into the ground layer. The blocking remover disclosed by the invention has beneficial effects that the blocking remover disclosed by the invention can be applied to decompression and augmented injection of a water injecting well and deep unblocking of an oil well; and the blocking remover has better effect while being applied to augmented injection of the water well in a reservoir non-homogeneous oil-field block.

The invention relates to a method for analyzing the heterogeneous property of an oil reservoir. The method comprises the following steps that 1, water injection parameters of a water injection well are collected, and a relative apparent water injectivity index Xi reflecting the water absorbing capacity of the oil reservoir is obtained; 2, the water injection intensity of each layer of a water absorbing profile of the water injection well is collected, and a water absorbing profile Lorentz coefficient Vi reflecting the heterogeneous property of the water absorbing profile of the water injection well is obtained through the Lorentz coefficient method; 3, fluid producing parameters of an oil well are collected, and a fluid producing intensity Lorentz coefficient Yi reflecting the fluid producing intensity of the oil well is obtained through the Lorentz coefficient method; 4, water cut rising parameters of the oil well are collected, and a well group water cut rising variable coefficient Wi reflecting the water cut rising differences of the oil well is obtained; 5, the fluid producing intensity of each layer of a production profile of the oil well is collected, and a production profile Lorentz coefficient Zi reflecting the heterogeneous property of the production profile of the oil well is obtained through the Lorentz coefficient method; and 6, a fuzzy decision-making evaluation model is built, and a comprehensive decision-making factor Fi is obtained. According to the method for analyzing the heterogeneous property of the oil reservoir, the heterogeneous property of the oil reservoir is quantified, and bases are provided for development and adjustment of oil fields.

The invention provides a similar limit water cut period take-turn water drive method for a multi-layer sandstone reservoir. The method includes the steps that a geological model based on single-cause sand bodies is established; on the basis that the geological model based on the single-cause sand bodies is established, a remaining oil distribution model based on the single-cause sand bodies is established; the single-cause sand bodies similar in property are combined into cause sand body sets; according to the reservoir characteristics of different single-cause sand body sets in a layer system and the remaining oil distribution conditions, the corresponding vectorization water drive adjustment scheme is determined; take-turn water drive based on the single-cause sand body sets is performed. With the similar limit water cut period take-turn water drive method for the multi-layer sandstone reservoir, influences of the heterogeneity of reservoir stratums of the multi-layer sandstone reservoir on water drive development can be reduced to the maximum, comprehensive displacement and balance displacement in a plane in the longitudinal direction of the single-cause sand bodies are achieved, and therefore a high-strength and high-efficiency water driving flow field can be established, and water drive sweep efficiency and water drive recovery efficiency can be improved substantially.

The invention relates to a method for improving recovery rate of a thick massive viscous oil reservoir by controlling burning gas injection speed, which mainly comprises the following steps of: determining the thickness and residual oil saturation of an oil layer at the burning front edge by stages according to the condition and rule of fire-flooding live wire wave by combining fine research results of double analogs in a massive oil reservoir chamber; then determining planar residual oil saturation and residual oil at different positions apart from a gas injection well, and predicting the burned section area of the burning front edge, the non-homogeneity of the reservoir and the optimal configuration relationship between the residual oil and the gas injection speed; and finally, dynamically adjusting the single-well gas injection speed by stages, and selecting a variable and lower burning gas injection speed to maintain stable and normal burning on the premise of ensuring combustion. The method can fulfill the purposes of improving the burning wave and volume of the massive oil reservoir, the development effect of the burning oil layer and the final recovery rate.

A branched flow channel type self-adaptation inflow control device comprises a base tube, an upper portion outer sleeve, a sand control screen tube, a lower portion outer sleeve and an inflow control box in a mutual connection mode. The type of fluid can be automatically identified, the level of flowing resistance can be automatically adjusted according to the characteristics of the fluid itself, before water breakthrough, certain resistance is exerted on the fluid, influences of a heeling effect and a reservoir stratum anisotropism can be offset, and therefore inflow sections along a horizontal shaft are even; once water breakthrough happens, flowing resistance will be increased obviously, so that flowing on a water layer section is restrained, and the long-period stable yield of an oil-gas well is guaranteed.

The invention investigates the effects of reservoir heterogeneity on IPR curves for horizontal wells drilled in heterogeneous solution gas drive reservoirs. To achieve the desired objective, a commercial simulator Eclipse is utilized to develop IPRs for horizontal wells producing oil from solution gas drive reservoirs. Firstly, a simulation model is developed where a base case is considered with typical rock, fluid and reservoir properties using a black oil model. Dimensionless IPR curves are generated by obtaining a set of points relating to flowing bottom-hole pressures to oil production rates. The effects of several reservoir and fluid properties such as bubblepoint pressure, oil gravity, residual oil saturation, critical gas saturation, initial water saturation, porosity and absolute permeabilities on the calculated curves are investigated.Reservoir heterogeneity is included in the simulation model by incorporating a semi-variogram function. Finally, a new single empirical IPR model is obtained for horizontal wells producing oil from heterogeneous solution gas drive reservoirs suitable for systems with different reservoir permeability. The new empirical IPR model is then compared to published correlations and is found to have a small and acceptable average absolute error of less than 2%. Furthermore, the invention also shows that bubble point pressure has significant effect on dimensionless IPR curves. However, plots for other properties indicate that although the curves are not identical, they are similar in shape and demonstrate much less variance than the bubble point pressure plot. Therefore, these properties have only a minor effect on calculated, dimensionless IPR curves.

The invention discloses a method for evaluating the rationality of low-permeability non-homogeneous gas reservoir fracturing horizontal well fracture parameters. The method comprises the steps that the parameters of the reservoir physical property, the fluid property, fracturing horizontal well fractures, a horizontal shaft and the propping agent property are collected; the permeability distribution condition of a non-homogeneous gas reservoir is divided into relatively homogeneous permeable zones in the length direction of the horizontal shaft, and the permeable zones contain artificial fractures; a fracturing fracture physical model of the permeable zones containing the artificial fractures and a mathematical model for fracture parameter evaluating are built; the high-speed non-darcy-flow effective permeability in the factures is corrected; a fracture yield model taking high-speed non-darcy flow of the fractures into account is solved, and an evaluating chart of the non-homogeneous gas reservoir fracturing horizontal well fracture parameters is built; the rationality of the low-permeability non-homogeneous gas reservoir fracturing horizontal well fracture parameters is evaluated. According to the method, the low-permeability gas reservoir heterogeneity characteristics and the comprehensive influence that the high-speed non-darcy-flow exists in the fracturing horizontal well fractures can be taken into account, and therefore the fracture parameters of all sections of a low-permeability non-homogeneous gas reservoir fracturing horizontal well are quickly and efficiently evaluated.

The invention provides a method for adjusting the variable flow line vector of thick-bed oil reservoirs. The method for adjusting the variable flow line vector of thick-bed oil reservoirs includes: step 1, conducting reservoir heterogeneity research; step 2, establishing a numerical simulation model, and Carry out history matching; step 3, conduct research on the distribution of remaining oil saturation; step 4, carry out the design of the well pattern variable flowline adjustment scheme; step 5, use numerical simulation technology to predict the ultimate recovery of the variable flowline scheme, according to Then optimize the variable streamline scheme; step 6, optimize the water injection parameter vector, and use numerical simulation technology to predict the final recovery factor of the vector water injection parameter optimization scheme. The variable streamline vector adjustment method for thick-bed reservoirs is highly practical, and can effectively slow down the production decline and water-cut rise of thick-bed reservoirs during the ultra-high water cut period, and improve the water flooding development effect.

The invention relates to a high-water-content oil reservoir residual oil diving method. The method comprises the steps of determining an oil reservoir flow field quantitative characterization method by analyzing flow field geological main control factors of different oil reservoirs, further determining an initial flow field distribution rule and mode, analyzing a dominant flow field distribution rule and mode by combining development dynamics and other oilfield development later-stage data, and finally utilizing the dominant flow field-mode to analyze the dominant flow field distribution rule and mode; adopting a dominant flow field-initial flow field difference method to find residual oil, and exploiting the residual oil. According to the high-water-content oil reservoir remaining oil diving method provided by the invention, on the basis of oil reservoir classification, the influence of reservoir heterogeneity and structural characteristics on an initial flow field is deeply analyzed, and by re-analyzing the oil reservoir flow field in the later development stage, a dominant flow field is compared with the dominant flow field. The initial flow field forms a knowledge of a region beneficial to the distribution of residual oil in the later period of development, potential residual oil is dug in a targeted manner, the utilization degree and the final recovery ratio of the out-of-control reserves of the oil reservoir are improved, the oil field yield decreasing amplitude is effectively reduced, and the final recovery ratio of the oil reservoir is obviously improved.

The invention provides a method for improving CO2 preservation quantity and crude oil recovery yield. The method comprises the following steps of obtaining relationship curve of pressure level and oildisplacement efficiency according a long slender pipe oil displacement experiment; determining the target region pressure safe limit by using a CO2 oil displacement and target region cover layer andfracture layer preservation stability evaluation method; preferably selecting the reasonable pressure maintaining level by using an oil reservoir value simulation method; realizing the CO2 longitudinal direction balanced displacement according to reservoir parameters, production parameters and process methods; realizing the CO2 plane balanced displacement by using variable-well-pattern well spacing and different reservoir transformation according to the anisotropy and remaining reserve abundance distribution condition of the target region reservoir; regulating the injection mining flow line through the mode optimization of the injection mode, the injection speed, injection mining regulation and control and foam blockage regulation. The invention provides a feasible method for improving theCO2 preservation quantity and the crude oil recovery yield; great application prospects are achieved in aspects of energy saving, emission reduction, CO2 resource utilization and crude oil recovery yield improvement.

The invention provides a method and a device for determining reservoir heterogeneity. The method includes the following steps: reservoirs to be measured are equally grouped according to a preset depth interval, so that a plurality of depth groups are obtained; a permeability mean value of each depth group among the plurality of depth groups is obtained; according to the permeability mean value of each depth group, a vertical heterogeneity index of the reservoirs to be measured is worked out; and according to the vertical heterogeneity index of the reservoirs to be measured, a heterogeneity degree of the reservoirs to be measured is determined. In the embodiment of the invention, the reservoirs to be measured are divided into the plurality of depth groups, the permeability mean value of each depth group is calculated, and thereby the heterogeneity of the whole reservoirs is finally determined; because all stratum contents in each depth group among the reservoirs to be measured, rather than core samples, are the basis in the process of determining heterogeneity, relative to the prior art, the determined heterogeneity result is more accurate, and based on the more accurate heterogeneity result, the efficiency of oil and gas exploitation can be effectively increased.

The invention provides a bioclastic limestone reservoir heterogeneity research method. The method specifically comprises the following steps that sedimentary microfacies dividing is performed on a bioclastic limestone reservoir; a pore permeability parameter distribution interval standard of different microfacies is built; a region sedimentary facies map is drawn, and the relation between the productivity and sedimentary microfacies belt distribution state of different well locations is inspected; the corresponding relation between main diagenesis types and lithological characters is built through diagenesis type analysis; pore structure research and reservoir classification are performed, and pore diagenetic degree classification grades of different diagenesis types are supplied according to a reservoir classification result; an imitated variable coefficient, an imitated dart coefficient and an imitated range of the bioclastic limestone reservoir are calculated, and numerical intervals of all-grade heterogeneity parameters are supplied. According to the method, the bioclastic limestone reservoir heterogeneity is researched jointly from the macroscopic aspect and microcosmic aspect, and the improvement of the reservoir permeability mechanism knowledge and the guidance of the effective development of oil and gas fields are facilitated.

The invention discloses a shale heterogeneity classification and comparative method, which comprises:(1) building the isochronous stratigraphic comparison lattice for the vertical heterogeneity classification of the shale reservoir by the high-frequency sequence classification and comparation; (2) studying the macro heterogeneity in the isochronous stratigraphic comparison lattice and analyzing and establishing the vertical and horizontal change characteristics of the macro heterogeneity of different high-frequency sequences of the shale reservoir in the isochronous stratigraphic comparison lattice; (3) studying the micro heterogeneity in the isochronous stratigraphic comparison lattice and establishing the vertical and horizontal change characteristics of the micro heterogeneity of different high-frequency sequences of the shale reservoir; (4) classifying and comparing small layers, and conducting detailed classification of small layers in the isochronous stratigraphic comparison lattice according to the heterogeneity characteristics of the shale reservoir in research results of the macro heterogeneity and the micro heterogeneity. The method selects the shale reservoir with high heterogeneity both in vertical and lateral directions as stable and continuous output selecting layer and provides geological basis for shale gas' exploiting vertical selecting layer, plane division and development technique policy in the future.

The invention discloses a water-controlling and oil-stabilizing inflow controller used for an oil extraction system. The water-controlling and oil-stabilizing inflow controller comprises a base pipe, a throttling part and a sliding pipe. The throttling part comprises a plate-shaped body, a rotational flow cavity, an inlet channel and a throttling hole formed in the middle of the rotational flow cavity. Formation fluid enters the rotational flow cavity along the side wall of the rotational flow cavity and flows into a throttling nozzle through the throttling hole. The sliding pipe is arranged in the base pipe in a sleeved mode and provided with flow guide holes penetrating through the side wall. When the sliding pipe is constructed to be in a first position, the pipe wall of the sliding pipe blocks the throttling nozzle, and when the sliding pipe is constructed to be in a second position, the flow guide holes communicate with the throttling nozzle. The water-controlling and oil-stabilizing inflow controller has secondary adjustment ability, so that the toe effect and the influence of oil reservoir heterogeneity are reduced. In addition, the blocking possibility is small, a larger flow passing area is obtained, a good self-cleaning function is achieved, and the water-controlling and oil-stabilizing purposes can be achieved more effectively.

The invention discloses a delta sand body internal structure analysis method based on overlapped lobes. The method includes the following steps that firstly, data are collected; secondly, a top interface and a bottom interface of a layer are determined; thirdly, the interface characteristics of the lobes are determined by analyzing the lithological and electrical characteristics of lobe boundaries, and the lobe boundaries are determined; fourthly, reservoir internal structure characteristics are recognized through bottom leveling, and the mutual relation between the lobes is preliminarily analyzed; fifthly, based on recognition of the lobes, the lobes are divided into a composite lobe level and a single lobe level, the corresponding relation between the lobes is analyzed, the relation between the lobes is determined, comparison analysis is conducted on the distribution characteristics of the lobes on a section, and interwell distribution of the lobes is determined; sixthly, the plane distribution range and the distribution shape of the lobes are determined; seventhly, the reservoir structure is verified. By the adoption of the method, a delta sand body internal structure is accurately described, reliability and practicality are high, a new thought is provided for understanding of anisotropy of reservoirs, and the method can be widely applied to the technical field of exploitation and development of oil and gas.

The invention discloses a high-temperature high-salt oil reservoir in-situ emulsion system and an application thereof. The in-situ emulsion system comprises 0.1-0.3% of alkylphenol(alcohol) polyoxyethylene ether sulfonate, 0.05-0.1% of sodium dodecyl sulfate, 0.05-0.1% of nano silicon dioxide and the balance of water. The interfacial tension of the in-situ emulsion system and crude oil can reach 10 <-2>-10<-3> mN / m, and under a shearing condition, the crude oil and water can form an O / W emulsion, and viscosity of the emulsion is greater than viscosity of water, so that the mobility ratio can be effectively improved. When being applied to chemical flooding of a high-temperature high-salt oil reservoir, emulsion droplets can block large pores in a porous medium through a Jamin effect, heterogeneity of a reservoir stratum is improved, and a low-permeability layer is started, so that the recovery rate is greatly improved. Meanwhile, the anti-aging property of the system under a high-temperature high-salt condition is good, and the oil-displacing requirement of high-temperature high-salt oil reservoirs can be met.

The invention discloses a method for evaluating heterogeneous characteristics of a reservoir continuously and quantitatively by applying resistivity imaging logging data. The resistivity imaging logging data of each depth point distributed along a well circumference is converted to porosity through a formation factor formula; a heterogeneous characteristic spectrum can be obtained by studying the distribution of different depth porosity data; morphological characteristics of the heterogeneous characteristic spectrum are analyzed; heterogeneous characteristic parameters, such as a mean value, a homogeneity coefficient, a variance, a peak value, a quality factor and the like, are calculated; and researches, such as lithology identification, effectiveness classification of the reservoir, remaining oil distribution and the like, can be carried out. The method provided in the invention improves the ability of the logging data to evaluate the heterogeneous characteristics of the reservoir; and a great number of parameters capable of reflecting the heterogeneous characteristics of the stratum are obtained. Compared with the method of purely using the conventional logging data to evaluate the heterogeneous characteristics of the reservoir, the new method has incomparable advantage, the method has higher promotional value and social benefit.

The invention provides a productivity prediction method of fishbone horizontal well segmented coupling. The method includes the steps of firstly, using a segmenting method to segment a complex structure; secondly, building a shaft flow model; thirdly, using an iteration method to solve an equation set of fluid flow in an oil reservoir and flow coupling in a shaft; fourthly, solving the model after space transformation; fifthly, using an s-K* method to process stratum anisotropic conditions. The method has the advantages that the complex well body structure can be described precisely, the complex shaft flow features can be reflected reasonably, the reservoir anisotropy is considered, and the method conforms to actual oil reservoir conditions and is high in calculation precision and applicable to oil fields.

The invention discloses a heterogeneous physical simulation and foam displacement evaluation system for a strong bottom water oil reservoir. The heterogeneous physical simulation and foam displacementevaluation system for the strong bottom water oil reservoir comprises a heterogeneous physical simulation device and a foam displacement evaluation device, and the heterogeneous physical simulation device is used for simulating interlayer and different reservoir rhythm segments and obtaining a water cone shape; and the foam displacement evaluation device is connected with the heterogeneous physical simulation device and used for performing visual observation before and after foam displacement, performing foam sampling and completing a foam displacement of reservoir oil water plugging experiment and hydrodissection metering of oil gas. According to the heterogeneous physical simulation and foam displacement evaluation system for the strong bottom water oil reservoir, reservoir heterogeneity, bottom water displacement of reservoir oil with different strength and foam displacement of reservoir oil simulation can be carried out, oil reservoir bottom water can be simulated in a constant-speed and constant-voltage mode, the simulation conditions are evaluated and fed back through the foam displacement evaluation device, oil reservoir development is guided, and good experimental supportis provided for the oil reservoir development.

The invention discloses a double tracer method for identifying the heterogeneity of a water-drive reservoir. According to the method, the heterogeneity of the water-drive reservoir is identified by using a tracer A and a tracer B of which diffusion coefficients have obvious difference. The double tracer method is characterized in that the tracer A and the tracer B of which the diffusion coefficients have obvious difference respectively reflect the total pore size volume of heterogeneous porous media and the pore size volumes of mobile areas in the heterogeneous porous media, thus quantitatively identifying existing conditions of high permeability layers in the heterogeneous porous media and evaluating sweep conditions of injected water. The double tracer method disclosed by the invention can be used for quantitatively identifying the existing conditions of the high permeability layers in the heterogeneous porous media and evaluating the sweep conditions of the injected water, and can be used for actual production of a mine field, and indoor evaluation of the heterogeneity of a physical simulation model and profile control and displacement properties of various profile control and displacement agents of an injection well; the double tracer method has the advantages of low workload of the mine field, low cost, convenience and quickness in data interpretation and high maneuverability.

The invention discloses a deep sea lobe reservoir configuration characterization method based on well-to-seismic mode fitting, which comprises the following steps: determining configuration element types and well-to-seismic response characteristics thereof; dividing a deep sea leaf configuration interface system; representing the reservoir configuration of the leaf system level; representing the reservoir configuration of the composite lobe series level; and characterizing the reservoir configuration of the composite lobe level. An idea is provided for carrying out underground reservoir configuration research by utilizing well-to-earthquake combination; scientific and reasonable prediction of flow paths, geometrical shapes, scale sizes and mutual superposition relations of sand bodies caused by different levels of deposition of deep sea leaves is realized. Effective characterization of reservoir heterogeneity of the deep-sea leaf oil and gas reservoirs is achieved, so that important geological basis and guidance are provided for well position deployment, well pattern design, injection-production correspondence analysis, remaining oil distribution prediction and the like of the deep-sea leaf oil and gas reservoirs, and therefore, the method has important practical engineering significance for reducing drilling risks of the deep-sea leaf oil and gas reservoirs and efficiently developing the deep-sea leaf oil reservoirs.

The invention discloses an optimal well-location deployment method and device aiming at a small fault block reservoir, and belongs to the technical field of petroleum exploitation. The optimal well-location deployment method comprises the steps that 1, the proportion of injection-production units in a block is determined; 2, the geometric boundary of the block is extracted; 3, an initial well location is determined in the geometric boundary of the block; 4, on the basis of the initial well location, the injection-production units are added one by one, and the well locations of the newly-addedinjection-production units are optimized until the recovery ratio or the net present value is no longer increased; and 5, the most proper number of the injection-production units is selected accordingto the relation curve and the actual target between the number of the injection-production units and the recovery ratio. According to the optimal well-location deployment method and device, convergence is good, factors such as the plane geometric shape of a fault block, the size of the fault block, spatial distribution characteristics of an oil sand body, heterogeneity of a reservoir stratum, anddirectionality of the permeability are fully taken into account, and the recovery ratio or the net present value of the reservoir can be increased.

The present invention discloses an oil production water control apparatus, a directional well completion oil production pipe and a completion method thereof. The water control apparatus comprises an outer pipe; a central pipe sleeved in the outer pipe; a pipe wall of the central pipe is provided with a fluid through hole penetrating the inside thereof; and a water control mechanism installed between the outer pipe and the central pipe. The water control mechanism has an approximately disc-shaped swirling flow cavity, inflow ports, an outflow port, and inflow passages; the cross-section shape of the swirling flow cavity radially vertical to the central pipe is circular and the center line is parallel to the radial direction; the outflow port communicates the swirling flow cavity and the fluid through hole; the inflow passages communicates the inflow ports and the swirling flow cavity; and the inflow passages penetrate the swirling flow cavity so that fluid input into the swirling flow cavity can form swirling flow. The water control apparatus can automatically adjust generated additional resistance according to fluid flow and fluid physical property of a producing horizon, and the influence of oil reservoir heterogeneity can be reduced.

The invention relates to a method and device for predicting the spatial distribution of glutenite based on chaotic properties, and belongs to the technical field of geophysical prospecting for petroleum. In the invention, a tensor algorithm is used to obtain a three-dimensional spatial variable of the seismic reflection amplitude, a gradient vector for each point is calculated, and a corresponding gradient covariance matrix is established. The chaotic properties of an earthquake are calculated using the eigenvalue of the covariance matrix. The distribution of glutenite is predicted by using the chaotic properties. Since the chaotic properties can well reflect the change point of the seismic reflection cophase axis, the structural abrupt change point, the fault breakpoint, the reservoir heterogeneity change point, and highlight the internal reflection structure and boundary of the special geological body, minor fault and microcrack. Therefore, the method and device can effectively reflect the sedimentary characteristics and tectonic morphology of the small glutenite and non-homogeneous special geological body, describe the internal reflection structure of the glutenite, predict the strong sedimentary facies belt, and provide the basis for the well site deployment.

The invention discloses a fractal characterization method of organic shale micro-pores based on CO2 adsorption, and belongs to the technical field of unconventional oil gas exploration and development. According to the method, the fractal theory of microporous medium in material chemistry is utilized to calculate the fractal dimension of organic shale micropores, the fractal feature is analyzed and calculated by utilizing adsorption data of CO2 in shale micro-pores through a multi-step linear and nonlinear fitting process, and a fractal dimensional value is finally obtained. The method can provide a reliable basic analysis parameter for evaluating the difference of porous structures of different storage layers, and can be used for calculating organic shale microporous fractal dimensions with different types in different regions, providing reference data to the complex degree of microporous structures and further guiding heterogeneous feature expression of the storage layers.

The invention relates to a low-permeability sandstone reservoir composite polymer type profile control agent and its application method, which relate to the field of oilfield applied chemistry. The present invention injects low-permeability sandstone reservoirs in the form of double slugs. The pre-slug is a multi-molecular compound polymer, which can be combined with insoluble suspended matter particles in the reservoir to form a polymer with a molecular coil structure around the core. Selective plugging of micro-fractures and large pores in the reservoir; the rear slug is a low-viscosity compound polymer, and an appropriate amount of clay stabilizer and surfactant is added to control and flood unplugged areas, which can suppress low-viscosity The phenomenon of clay swelling in seepage sandstone reservoirs can improve the deposition of wax, colloid and asphaltene near the wellbore; the invention can improve the heterogeneity of reservoirs, increase the follow-up water flooding sweep coefficient, and suppress dead oil areas in low-permeability sandstone reservoirs Formed to improve the disadvantages of traditional oil recovery methods such as low recovery rate and poor economic benefits of low-permeability sandstone reservoirs.

The invention discloses a method for optimizing the fracture position of an ultra-low permeability heterogeneous gas reservoir fractured horizontal well. The method mainly comprises the following steps that basic parameters of a reservoir stratum, fluid and a horizontal well shaft are collected; a heterogeneous gas reservoir is partitioned into at least to vadose zones in the length direction of the horizontal well shaft, wherein artificial fractures are contained in the vadose zones; a vadose unit simulation model of each vadose zone is established; vadose simulation models of at least two vadose units are established; the vadose simulation models of all the vadose units are coupled, and the yields of the heterogeneous gas reservoir fractured horizontal well are calculated; the yields are compared, and the fracture position where the ultra-low permeability heterogeneous gas reservoir fractured horizontal well has the highest yield is selected. According to the technical scheme, the influences of reservoir stratum heterogeneity and the starting pressure gradient are fully considered, the defect that in the prior art, only the fracture position of a homogeneous gas reservoir fractured horizontal well without the consideration of the starting pressure can be selected is overcome, and thus the effectiveness and the effect of transformation of the ultra-low permeability heterogeneous gas reservoir fractured horizontal well are improved.