Judgment method for oil-gas phase state of condensate gas reservoir horizontal well section

Abstract

The invention relates to a condensate gas reservoir horizontal well section oil-gas phase state judgment method, and belongs to the technical field of condensate gas reservoir oil-gas exploration and development. According to the method, hydrocarbon component data information of logging gas logging in the drilling process is utilized, a gas-liquid hydrocarbon coefficient formula is established, then normalization processing is conducted, normalized data are displayed in the same scale through a curve and correspond to the actual productivity of a well, and a judgment standard of the oil-gas phase state is established. When the oil-gas phase state of the condensate gas reservoir horizontal well section is quickly and qualitatively predicted, the relative contents of the condensate oil and the natural gas in the stratum of the condensate gas reservoir horizontal well section are intuitively judged by comparing two curves of liquid hydrocarbon and gas-liquid hydrocarbon coefficients according to the established judgment standard. A reference basis is provided for optimizing a gas testing interval and optimizing a reservoir transformation process, the method is a novel method which is low in cost, simple, convenient, visual, efficient and reliable in result, and geological evaluation data is provided for a horizontal well multi-section fracturing technology.

Description

Technical Field

[0001] This invention relates to a method for determining the oil and gas phase state of horizontal well sections in condensate gas reservoirs, belonging to the field of oil and gas exploration and development technology for condensate gas reservoirs. Background Technology

[0002] Condensate gas reservoirs are a type of gas reservoir that falls between oil and gas reservoirs. The hydrocarbon composition of condensate gas reservoirs mainly includes gaseous hydrocarbons, liquid hydrocarbons, and non-hydrocarbons. Condensate oil in condensate gas reservoirs exists in a gaseous state under high temperature and pressure conditions in the formation. However, when the formation pressure is lower than the dew point pressure, the condensate oil will precipitate from the gaseous state, forming a gas-liquid two-phase system. The hydrocarbon system of condensate gas reservoirs is a special type of hydrocarbon system, called a condensate oil-gas system. The characteristics of the condensate oil-gas system are: firstly, a high gas-oil ratio; and secondly, a high content of light hydrocarbon components, which is the material basis of condensate oil-gas reservoirs. The phase characteristics of hydrocarbon fluids in condensate gas reservoirs are complex and diverse, and their exploration and development differ significantly from those of natural gas and oil. The phase characteristics of oil and gas reservoir fluids are the foundation for oil and gas resource exploration and evaluation, providing theoretical and technical support for determining oil and gas reservoir types, calculating reserves, researching oil and gas reservoir engineering and production processes, and developing development plans. Therefore, the evaluation of the fluid phase state of condensate gas reservoirs is a prerequisite for the development and evaluation of condensate gas reservoirs and is of great significance in oil and gas reservoir exploration and development.

[0003] Numerous studies have shown that the phase characteristics of condensate gas reservoirs are fundamentally determined by hydrocarbon components, and changes in hydrocarbon components will alter the critical temperature and critical pressure of the fluid.

[0004] For areas where downhole formation fluid composition data have been obtained, empirical statistical methods, such as the hydrocarbon composition triangle diagram method, the Pixler interpretation chart method, and the hydrocarbon ratio method (3H method), can be used to make relatively accurate quantitative judgments on the oil, gas, and water content of reservoirs, classifying reservoirs into three different types: gas layers, oil layers, and non-producing layers, to determine the type of oil and gas reservoir. Chinese invention patent CN107448195A, published on December 8, 2017, discloses a method and application for identifying light oil layers and condensate gas layers in formations. It proposes using gas composition measurement data from different test wells at different depths to identify light oil reservoirs and condensate gas reservoirs in formations, in order to determine whether it is an oil reservoir or a condensate gas reservoir.

[0005] For areas where formation fluid data is not yet available, reservoir types can be identified based on gas logging data. Gas logging, a commonly used logging method, determines the activity of oil and gas reservoirs by detecting the gas content carried by the drilling fluid returning from the bottom of the well. Chinese invention patent CN111502650A, published on August 7, 2020, discloses a method and application for identifying condensate gas reservoirs using gas logging-derived parameters. By detecting alkane gases in the drilling fluid, the relative percentages of methane and ethane in the hydrocarbon components, the C1 / C2 ratio, and the C2 / C3 ratio are calculated to identify whether it is a condensate gas reservoir. Chinese invention patent CN108798661A, published on November 13, 2018, discloses a method for identifying oil well reservoirs and fluid-bearing properties using logging gas logging component parameters. It utilizes component differences combined with drilling time parameters to establish oil index calculation models, water risk index calculation models, and oil dominance index calculation models to characterize the development of oil reservoirs and their fluid-bearing properties. Chinese invention patent CN110159263A, published on August 23, 2019, discloses a method for determining reservoir fluid properties using a reverse-order index based on the superposition of logging gas logging component spectra. It establishes a reverse-order superposition method based on characteristic parameters of logging gas logging components, according to the quantitative relationships between alkane components, to distinguish between oil-bearing and water-bearing properties.

[0006] The aforementioned disclosed information has, to some extent, solved the problem of qualitatively and quickly identifying condensate gas reservoirs using field logging data. However, the disclosed information focuses on analyzing and evaluating formation fluid data in explored areas or tested oil and gas wells, or using vertical well gas logging data to statistically analyze the number of gas logging components, relative percentage of methane, relative percentage of ethane, C1 / C2 ratio, and C2 / C3 ratio to determine the type of gas reservoir encountered and whether it is a condensate gas reservoir. The hydrocarbon ratio method (3H method), proposed by Haworth J.H. et al. in 1985, uses three ratios—humidity ratio, equilibrium ratio, and characteristic ratio—calculated from C1 to C5 hydrocarbons to determine fluid properties. C1, C2, C3, C4, and C5 represent methane, ethane, propane, butane (sum of normal and isomers), and pentane (sum of normal and isomers), respectively. The main analytical methods are as follows: ① Humidity ratio: This is the ratio of the sum of C2 to C5 hydrocarbon concentrations to the sum of C1 to C5 hydrocarbon concentrations. Its magnitude is a characteristic indicator of the humidity of oil and gas. The humidity ratio (WH) is a regional evaluation index, representing the relative abundance of heavy components in all gas: 1) WH < 0.5, judged as dry gas; 2) WH between 0.5 and 17.5, judged as gas or coexistence of oil and gas; 3) WH between 17.7 and 40, judged as oil; 4) WH > 40, judged as heavy oil or residual oil. ② Balance ratio: Used to identify coalbed methane effects. Because coal-bearing strata contain large amounts of C1 and C2, but lack propane, butane, and pentane, the balance ratio may remain constant, leading to interpretation distortion. In evaluation, the balance ratio should be used in conjunction with the moisture ratio. Therefore, this index can be used to distinguish between coalbed methane and oil-bearing methane shows. ③ Characteristic ratio: It can be used to interpret a type of ambiguous display between oil and gas. This index is used to determine the reservoir type and identify coal seams, oil layers, and gas layers. When the thickness of the oil-bearing gas layer indicated by the 3H method is too large, geological logging lithology data should be combined to accurately determine the upper and lower depth limits of the reservoir; and in comprehensive interpretation, well logging interpretation data should be referenced to determine the top and bottom depths of the reservoir. None of the above can solve the problem of predicting the oil and gas phase state before fracturing in the horizontal section of horizontal wells in newly explored condensate gas reservoirs. Currently, horizontal well drilling and multi-stage fracturing technologies are widely used in unconventional oil and gas exploration and development. However, the prediction of formation fluid phases in the horizontal section of a horizontal well before fracturing is still lacking. Therefore, for new unconventional condensate gas reservoirs, predicting the formation fluid phases in the horizontal section of a newly drilled horizontal well before fracturing is crucial for the optimized implementation of subsequent multi-stage fracturing technologies. Summary of the Invention

[0007] The purpose of this invention is to provide a method for determining the oil and gas phase state of horizontal well sections in condensate gas reservoirs, providing a method for rapid qualitative determination of the oil and gas phase state of horizontal well sections in condensate gas reservoirs in the prior art.

[0008] To achieve the above objectives, the technical solution of the method for determining the oil and gas phase state in a horizontal well section of a condensate gas reservoir in this invention is as follows:

[0009] A method for determining the hydrocarbon phase state in a horizontal well section of a condensate gas reservoir, comprising the following steps:

[0010] (1) Collect continuous gas logging data from a single well in the target area; the data includes total hydrocarbon content and the contents of methane, ethane, propane, isobutane, and n-butane;

[0011] (2) Based on the data obtained in step (1), calculate the contents of gaseous hydrocarbons and liquid hydrocarbons respectively, and calculate the gas-liquid hydrocarbon coefficient C according to the following formula. 气 / 液 =∑C 1-4 / ∑C5 + , where ∑C 1-4 For the sum of gaseous hydrocarbon content, ∑C5 + For liquid hydrocarbon content and;

[0012] (3) Normalize the liquid hydrocarbon content and gas-liquid hydrocarbon coefficient obtained in step (2) and correspond them with the actual production capacity of the single well in step (1) to establish a judgment standard for oil and gas phase state, and judge the oil and gas phase state of the horizontal well section according to the judgment standard.

[0013] The beneficial effects of the above technical solution are as follows: The method for determining the hydrocarbon phase state of horizontal well sections in condensate gas reservoirs according to the present invention is a pioneering invention. This invention utilizes hydrocarbon component data from well logging during the drilling process, establishes a gas-liquid hydrocarbon coefficient formula, performs normalization processing, and displays the normalized data as a curve on the same scale, corresponding to the actual production capacity of the well, thus establishing a standard for determining the hydrocarbon phase state. Using this established standard, a rapid qualitative prediction of the hydrocarbon phase state in horizontal well sections of condensate gas reservoirs with similar or identical formation conditions can be achieved. When conducting rapid qualitative prediction of the oil and gas phase states in horizontal well sections of condensate gas reservoirs, the relative contents of condensate oil and natural gas in the formation of the horizontal well section are intuitively determined by comparing two curves of liquid hydrocarbon and gas-liquid hydrocarbon coefficients based on the established judgment criteria. This provides a reference for selecting the best gas testing section and optimizing the reservoir stimulation process. It is a new method that is low-cost, simple, intuitive, efficient, and reliable. It provides geological evaluation data for multi-stage fracturing technology in horizontal wells, so as to optimize the fracturing process in horizontal well sections, improve the fracturing effect of horizontal wells, and achieve the geological goal of obtaining high-yield industrial gas flow.

[0014] Specifically, horizontal wells and vertical wells have different construction purposes: In petroleum engineering, based on the shape of the wellbore trajectory, they are mainly classified into two categories: vertical wells and directional wells. Vertical wells are the most basic well type, while directional wells include a variety of complex well types, such as horizontal wells, double horizontal wells, extended reach wells, multi-branch wells, U-shaped wells, connecting wells, and multi-functional combination wells. Usually, after discovering oil and gas layers using exploratory wells (often vertical wells), for thin oil and gas layers or unconventional shale gas / tight gas layers, a horizontal well type is used, which maintains a certain length of horizontal well section in the target layer. The maximum inclination angle of a horizontal well is not less than 86°, the purpose of which is to increase the exposed area of ​​the oil and gas layer and improve formation productivity.

[0015] Furthermore, during vertical well drilling, multiple formations are typically drilled through, resulting in the encounter of various types of oil and gas show zones, such as oil layers, water layers, gas layers, and condensate gas layers. These fluid properties differ significantly, making identification easier with less interference. Horizontal wells, on the other hand, select a specific target formation, create a window, and then drill along the formation. Within this defined horizontal well drilling area, changes in the formation can lead to encountering miscible fluids (e.g., a mixture of oil and gas layers), resulting in greater interference and making identification more difficult.

[0016] As a further improvement, the judgment criteria in step (3) are as follows: when the normalized gas-liquid hydrocarbon coefficient is <0.1 and the normalized liquid hydrocarbon content is <0.1, the horizontal well section is a low-yield layer and is not identified; when the normalized gas-liquid hydrocarbon coefficient is >0.1 and the normalized liquid hydrocarbon content is <0.1, the horizontal well section is in the gas phase; when the normalized gas-liquid hydrocarbon coefficient is <0.1 and the normalized liquid hydrocarbon content is >0.1, the horizontal well section is in the liquid phase; when the normalized gas-liquid hydrocarbon coefficient is >0.1 and the normalized liquid hydrocarbon content is >0.1, the horizontal well section is in both gas and liquid phases.

[0017] As a further improvement, step (2) includes data preprocessing; the preprocessing is to remove the following two types of data: ① methane content + ethane content + propane content + isobutane content + n-butane content ≥ total hydrocarbon content, ② methane content ≥ total hydrocarbon content.

[0018] As a further improvement, the gaseous hydrocarbon content and ∑C in step (2) are... 1-4 The content of methane, ethane, propane, isobutane, and n-butane.

[0019] As a further improvement, the liquid hydrocarbon content and ∑C5 in step (2) are... + This is the difference between the total hydrocarbon content and the sum of the gaseous hydrocarbon content. Attached Figure Description

[0020] Figure 1 This is a flowchart of the technical solution of Embodiment 1 of the present invention;

[0021] Figure 2 This is a schematic diagram of the horizontal well *HF in Embodiment 1 of the present invention;

[0022] Figure 3 This is a schematic cross-section of the phase state analysis of the HF well in Embodiment 1 of the present invention, showing the actual production capacity analysis.

[0023] Figure 4 This is a cross-sectional diagram of the criteria for determining the phase state of a horizontal well in Embodiment 1 of the present invention;

[0024] Figure 5 This is a schematic cross-section of the phase state analysis of the L3H well horizontal well in Experiment Example 1 of this invention, showing the actual production capacity analysis. Detailed Implementation

[0025] Currently, horizontal well drilling and multi-stage fracturing technologies are widely used in unconventional oil and gas exploration and development. However, the prediction of formation fluid phases in the horizontal well section before fracturing and stimulation remains a gap. For a new unconventional condensate gas reservoir exploration area, how can the formation fluid phases in the horizontal well section be predicted before fracturing and stimulation of a newly drilled horizontal well? To address this problem, this invention proposes a method for determining the oil and gas phases in the horizontal well section of a condensate gas reservoir. This invention utilizes hydrocarbon composition data obtained from drilling-while-drilling (DSD) measurements to calculate parameters such as liquid hydrocarbons and gas-liquid hydrocarbon coefficients, enabling rapid determination of the formation oil and gas phase distribution in the horizontal well section of the condensate gas reservoir. It visually determines the relative content of condensate oil and natural gas in the horizontal well section and delineates different phase characteristic segments. This provides a reference for selecting optimal testing zones, optimizing reservoir stimulation processes, and determining reasonable development methods for horizontal wells in new exploration areas. It is of great significance for improving gas well productivity, reducing anti-condensate pollution, and increasing recovery rates.

[0026] The method for determining the hydrocarbon phase state in a horizontal well section of a condensate gas reservoir according to the present invention specifically includes the following steps:

[0027] (1) Collect continuous gas logging data from a single well in the target area; the data includes total hydrocarbon content and the contents of methane, ethane, propane, isobutane, and n-butane;

[0028] (2) Based on the data obtained in step (1), calculate the contents of gaseous hydrocarbons and liquid hydrocarbons respectively, and calculate the gas-liquid hydrocarbon coefficient C according to the following formula. 气 / 液 =∑C 1-4 / ∑C5 + , where ∑C 1-4 For the sum of gaseous hydrocarbon content, ∑C5 + For liquid hydrocarbon content and;

[0029] (3) Normalize the liquid hydrocarbon content and gas-liquid hydrocarbon coefficient obtained in step (2) and correspond them with the actual production capacity of the single well in step (1) to establish a judgment standard for oil and gas phase state, and judge the oil and gas phase state of the horizontal well section according to the judgment standard.

[0030] As a further improvement, the judgment criteria in step (3) are as follows: when the normalized gas-liquid hydrocarbon coefficient is <0.1 and the normalized liquid hydrocarbon content is <0.1, the horizontal well section is a low-yield layer and is not identified; when the normalized gas-liquid hydrocarbon coefficient is >0.1 and the normalized liquid hydrocarbon content is <0.1, the horizontal well section is in the gas phase; when the normalized gas-liquid hydrocarbon coefficient is <0.1 and the normalized liquid hydrocarbon content is >0.1, the horizontal well section is in the liquid phase; when the normalized gas-liquid hydrocarbon coefficient is >0.1 and the normalized liquid hydrocarbon content is >0.1, the horizontal well section is in both gas and liquid phases.

[0031] As a further improvement, step (2) includes data preprocessing; the preprocessing is to remove the following two types of data: ① methane content + ethane content + propane content + isobutane content + n-butane content ≥ total hydrocarbon content, ② methane content ≥ total hydrocarbon content.

[0032] As a further improvement, the gaseous hydrocarbon content and ∑C in step (2) are... 1-4 The content of methane, ethane, propane, isobutane, and n-butane.

[0033] As a further improvement, the liquid hydrocarbon content and ∑C5 in step (2) are... + This is the difference between the total hydrocarbon content and the sum of the gaseous hydrocarbon content.

[0034] The present invention will be further described below with reference to specific embodiments. It should be noted that, without conflict, the various embodiments or technical features described below can be arbitrarily combined to form new embodiments. The equipment and raw materials used are all commercially available or commonly used in the art. Unless otherwise specified, the methods in the following embodiments are conventional methods in the art.

[0035] Unless otherwise specified, the operations described in the following embodiments are conventional operations in the art.

[0036] Unless otherwise specified, the raw materials used in the following embodiments are all conventional commercial products in the art.

[0037] A specific embodiment of the method for determining the hydrocarbon phase state in a horizontal well section of a condensate gas reservoir according to the present invention:

[0038] Example 1: A method for determining the hydrocarbon phase in a horizontal well section of a condensate gas reservoir.

[0039] The condensate gas reservoir analyzed in this embodiment is located in an oil and gas basin. This region has multiple continental shale gas and tight gas condensate gas reservoirs. The following description uses a dedicated exploration well (Shaanxi*HF well) in a continental shale gas formation as an example. This well is a horizontal shale gas well with low condensate oil content. Predictive analysis of the oil and gas phases in the horizontal section of the Shaanxi*HF well is conducted. The flowchart of the technical solution in this embodiment is as follows: Figure 1 As shown in the diagram, the horizontal well of the HF well is shown on page *. Figure 2 As shown. The specific implementation steps are as follows:

[0040] 1. Collect basic data

[0041] Collect single-well completion data, mainly including: basic data, well structure, well deviation, drilling fluid properties, well leakage, core data, logging results, drilling daily reports, etc. Focus on collecting continuous gas logging data, mainly including total hydrocarbon content and hydrocarbon gas component content (methane, ethane, propane, isobutane, n-butane, pentane and above), and non-hydrocarbon gases (hydrogen sulfide, carbon dioxide, etc.) (Table 1).

[0042] Table 1* HF Well Single Well Completion Data and Gas Logging Partial Data

[0043] well deep Drilling time All hydrocarbons methane Ethane propane Isobutane n-Butane <![CDATA[H2S]]> <![CDATA[CO2]]> 3000 6 1.862 1.554 0.138 0.031 0.006 0.006 0 0 3001 9 1.793 1.490 0.139 0.030 0.006 0.006 0 0 3002 10 2.173 1.790 0.178 0.040 0.008 0.007 0 0 3003 7 2.291 1.983 0.172 0.035 0.007 0.006 0 0 3004 11 1.480 1.375 0.111 0.023 0.005 0.005 0 0 3005 3 2.661 2.264 0.192 0.036 0.007 0.006 0 0 3006 4 2.141 1.801 0.142 0.030 0.006 0.006 0 0 3007 4 2.924 2.479 0.211 0.040 0.007 0.006 0 0 3008 4 3.890 3.385 0.274 0.051 0.008 0.007 0 0 3009 5 3.898 3.486 0.291 0.055 0.009 0.008 0 0 3010 4 4.050 3.566 0.295 0.056 0.009 0.008 0 0 3011 3 4.465 3.707 0.290 0.055 0.009 0.008 0 0 3012 3 4.852 4.323 0.324 0.061 0.010 0.009 0 0 3013 3 3.866 3.586 0.283 0.053 0.009 0.008 0 0 3014 21 2.998 2.685 0.221 0.043 0.008 0.007 0 0 3015 3 3.391 2.887 0.227 0.044 0.008 0.007 0 0 3016 3 3.719 3.254 0.262 0.051 0.009 0.008 0 0 3017 3 3.846 3.362 0.269 0.045 0.008 0.007 0 0 3018 3 3.959 3.523 0.286 0.055 0.009 0.008 0 0 …… …… …… …… …… …… …… …… …… …… 5019 7 1.006 0.839 0.097 0.020 0.004 0.003 0 0.0 5020 8 0.838 0.647 0.078 0.017 0.003 0.002 0 0.0 5021 7 0.684 0.523 0.065 0.014 0.003 0.002 0 0.0 5022 7 0.625 0.465 0.055 0.012 0.002 0.002 0 0.0 5023 6 0.625 0.470 0.053 0.011 0.002 0.002 0 0.0 5024 7 0.718 0.589 0.060 0.012 0.002 0.002 0 0.0 5025 7 0.703 0.575 0.058 0.011 0.002 0.002 0 0.0 5026 10 2.657 2.093 0.194 0.040 0.007 0.005 0 0.0 5027 8 7.496 7.107 0.461 0.068 0.010 0.007 0 0.0 5028 8 2.167 1.727 0.256 0.060 0.013 0.010 0 0.0 5029 5 2.951 3.088 0.135 0.016 0.003 0.002 0 0.0 5030 6 2.476 2.448 0.122 0.019 0.003 0.002 0 0.0 5031 7 2.509 2.401 0.165 0.028 0.005 0.004 0 0.0 5032 8 2.452 2.401 0.181 0.032 0.005 0.004 0 0.0 5033 5 2.483 2.333 0.193 0.034 0.006 0.004 0 0.0 5034 4 2.381 2.118 0.190 0.034 0.006 0.004 0 0.0 5035 5 2.412 2.223 0.204 0.036 0.006 0.004 0 0.0 5036 4 2.994 2.568 0.278 0.051 0.008 0.006 0 0.0 5037 11 3.078 2.685 0.300 0.058 0.008 0.006 0 0.0 5038 10 5.272 4.013 0.636 0.150 0.026 0.019 0 0.0 5039 9 6.032 4.168 0.718 0.172 0.031 0.022 0 0.0 5040 9 6.749 4.850 0.816 0.194 0.035 0.025 0 0.0 5041 10 6.372 4.804 0.740 0.166 0.030 0.021 0 0.0 5042 9 5.924 4.460 0.663 0.135 0.026 0.019 0 0.0

[0044] 2. Data Cleaning

[0045] The following two types of data were removed from the single-well gas logging data (Table 2):

[0046] ①C1+C2+C3+iC4+nC4≧total hydrocarbons;

[0047] ②C1≧All hydrocarbons;

[0048] In the formula, total hydrocarbons, C1, C2, C3, iC4, and nC4 are gas logging data, and C1, C2, C3, iC4, and nC4 represent the contents of methane, ethane, propane, isobutane, and n-butane, respectively.

[0049] Table 2* Data table of partial data after cleaning of gas logging in the horizontal section of Well HF.

[0050] well deep All hydrocarbons methane Ethane propane Isobutane n-Butane 3000 1.862 1.554 0.138 0.031 0.006 0.006 3001 1.793 1.490 0.139 0.030 0.006 0.006 3002 2.173 1.790 0.178 0.040 0.008 0.007 3003 2.291 1.983 0.172 0.035 0.007 0.006 3005 2.661 2.264 0.192 0.036 0.007 0.006 3006 2.141 1.801 0.142 0.030 0.006 0.006 3007 2.924 2.479 0.211 0.040 0.007 0.006 3008 3.890 3.385 0.274 0.051 0.008 0.007 3009 3.898 3.486 0.291 0.055 0.009 0.008 3010 4.050 3.566 0.295 0.056 0.009 0.008 3011 4.465 3.707 0.290 0.055 0.009 0.008 3012 4.852 4.323 0.324 0.061 0.010 0.009 3014 2.998 2.685 0.221 0.043 0.008 0.007 3015 3.391 2.887 0.227 0.044 0.008 0.007 3016 3.719 3.254 0.262 0.051 0.009 0.008 3017 3.846 3.362 0.269 0.045 0.008 0.007 3018 3.959 3.523 0.286 0.055 0.009 0.008 …… …… …… …… …… …… …… 5019 1.006 0.839 0.097 0.020 0.004 0.003 5020 0.838 0.647 0.078 0.017 0.003 0.002 5021 0.684 0.523 0.065 0.014 0.003 0.002 5022 0.625 0.465 0.055 0.012 0.002 0.002 5023 0.625 0.470 0.053 0.011 0.002 0.002 5024 0.718 0.589 0.060 0.012 0.002 0.002 5025 0.703 0.575 0.058 0.011 0.002 0.002 5026 2.657 2.093 0.194 0.040 0.007 0.005 5028 2.167 1.727 0.256 0.060 0.013 0.010 5034 2.381 2.118 0.190 0.034 0.006 0.004 5036 2.994 2.568 0.278 0.051 0.008 0.006 5037 3.078 2.685 0.300 0.058 0.008 0.006 5038 5.272 4.013 0.636 0.150 0.026 0.019 5039 6.032 4.168 0.718 0.172 0.031 0.022 5040 6.749 4.850 0.816 0.194 0.035 0.025 5041 6.372 4.804 0.740 0.166 0.030 0.021 5042 5.924 4.460 0.663 0.135 0.026 0.019

[0051] 3. Content of gaseous hydrocarbons and

[0052] Calculate the content of gaseous hydrocarbons.

[0053] Formula 1: ∑C 1-4 =C1+C2+C3+iC4+nC4;

[0054] In the formula, ∑C 1-4The values ​​represent the contents of gaseous hydrocarbons, and C1, C2, C3, iC4, and nC4 represent the contents of methane, ethane, propane, isobutane, and n-butane, respectively.

[0055] The specific results are shown in Table 4 below. Figure 3 As shown in the image.

[0056] 4. Liquid hydrocarbon content and

[0057] Calculate the liquid hydrocarbon content.

[0058] Formula 2: ∑C5 + =Total hydrocarbons - ∑C 1-4

[0059] In the formula ∑, C 1-4 For the sum of gaseous hydrocarbon content, ∑C5 + For liquid hydrocarbon content and.

[0060] The specific results are shown in Table 4 below. Figure 3 As shown in the image.

[0061] 5. Gas-liquid hydrocarbon coefficient

[0062] Calculate the gas-liquid hydrocarbon coefficient based on the results obtained in steps 4 and 5.

[0063] The gas-liquid hydrocarbon coefficient is a further refinement of the natural gas dryness factor formula. The natural gas dryness factor is the ratio of the methane content to the total hydrocarbon content (mainly methane, ethane, propane, butane, and pentane) in natural gas. It is closely related to the genetic type and thermal evolution maturity of the natural gas. In application, it relates to the classification and economic value of natural gas and is an important parameter in natural gas evaluation research. Dryness factor = C l / ∑C 2+ Natural gas with a dryness coefficient >95% is generally called dry gas, and <95% is called wet gas. Because condensate gas reservoirs have a lower thermal evolution maturity than wet gas reservoirs, their methane (C2) content is lower. 1 The content of ) is less than 90%, due to the presence of liquid hydrocarbons above pentane (C 5+ The content of hydrocarbons increases, and the total hydrocarbon content measured by well logging is low during field application. As can be seen from the calculated dryness coefficient values ​​in the examples, the calculated results are all far less than the judgment value of 95%. Therefore, the dryness coefficient cannot be used to effectively determine the fluid phase directly (see Table 3 for specific results).

[0064] Note: The hydrocarbons in natural gas are primarily alkanes, mainly methane, along with ethane, propane, butane, pentane, and small amounts of hexane and other hydrocarbons. Here, C... 2+ This refers to the ethane and other hydrocarbon components remaining after removing methane from the total hydrocarbon composition of natural gas; here, C... 5+ It refers to the pentane and other hydrocarbon components remaining after removing methane, ethane, propane, and butane from the total hydrocarbon composition of natural gas.

[0065] Table 3* Data table for calculating the drying coefficient from gas logging data in the horizontal section of HF well.

[0066]

[0067]

[0068] Therefore, a new parameter, the gas-liquid hydrocarbon coefficient, is introduced, as follows:

[0069] Formula 3: C 气 / 液 =∑C 1-4 / ∑C5 + ;

[0070] In the formula, C 气 / 液 For gas-liquid hydrocarbon coefficients, ∑C 1-4 For the sum of gaseous hydrocarbon content, ∑C5 + The values ​​represent the liquid hydrocarbon content. Specific results are shown in Table 4 below.

[0071] Table 4* Data table for calculating gas-liquid hydrocarbon coefficients from gas logging data in the horizontal section of HF well.

[0072]

[0073]

[0074] 6. Normalization processing

[0075] Normalization transforms data into decimals between (0, 1) and (1, 1), primarily for ease of data processing. Mapping data to the 0-1 range makes processing more convenient and faster. Normalization is a method of simplifying calculations, transforming dimensional expressions into dimensionless expressions, becoming pure scalars. This method is also known as min-max standardization or linear function normalization.

[0076] Calculation formula: Y = (x - min) / (max - min)

[0077] Y: Normalized data; X: Original data;

[0078] Xmax and Xmin: are the maximum and minimum values ​​of the original dataset, respectively.

[0079] Using the above formula and the data in Table 4, the sum of gaseous hydrocarbon content and sum of liquid hydrocarbon content obtained in step 4 are normalized and the gas-liquid hydrocarbon coefficients obtained in step 5 are normalized. The specific results are shown in Tables 5 and 6 below.

[0080] Table 5* HF Well Processing Original Data Set: Maximum and Minimum Values

[0081]

[0082] Table 6*HF Well Horizontal Section Gas Logging Data Calculation and Processing Section Data Table

[0083]

[0084]

[0085] 7. Place the liquid hydrocarbon content from step 6 and the normalized data of the gas-liquid hydrocarbon coefficients on the same coordinate system and display it as a curve, with the vertical axis representing the depth value, as shown below. Figure 3 As shown.

[0086] 8. Based on the liquid hydrocarbon content and gas-liquid hydrocarbon coefficients obtained in step 7, the formation hydrocarbon phase of the horizontal well section of the condensate gas reservoir is qualitatively determined. This is then verified in conjunction with the production profile monitoring results of the horizontal well tracer after completion. The judgment criteria are shown in Table 7. Figure 4 .

[0087] Table 7 Judgment Criteria

[0088]

[0089] Note: Tracer monitoring technology is a commonly used technique for evaluating the effectiveness of horizontal well fracturing and oil and gas production. Tracer monitoring involves adding a tracer to the fracturing fluid during multi-stage fracturing in a horizontal well. This tracer is pumped into the formation along with the fracturing fluid. During flowback, the concentration change (light intensity value) of the tracer in the flowback fluid is monitored intensively. Parameters such as the tracer production rate, flowback fluid production rate, and contribution rate of each stage (layer) are calculated to determine the oil, gas, and water production profile in the horizontal well, thereby analyzing and judging the staged fracturing effect of the oil and gas well. Due to current limitations in monitoring technology, only gaseous and liquid (oil and water mixture) tracers can be monitored in actual production.

[0090] Experiment Example 1 Field Application

[0091] The condensate gas reservoir analyzed in this experimental case is located in an oil and gas basin. This region has multiple continental shale gas and tight gas condensate gas reservoirs. The following is an example using a dedicated exploration well (L3H) in a continental tight gas formation. This well is a horizontal tight gas well in a low-condensate oil-bearing condensate gas reservoir. The specific steps for predicting and analyzing the oil and gas phases in the horizontal section of well L3H are as follows:

[0092] 1. Collect basic data

[0093] Collect single-well completion data, mainly including: basic data, well structure, well deviation, drilling fluid properties, well leakage, core data, logging results, drilling daily reports, etc. Focus on collecting continuous gas logging data, mainly including total hydrocarbon content and hydrocarbon gas component content (methane, ethane, propane, isobutane, n-butane, pentane and above), and non-hydrocarbon gases (hydrogen sulfide, carbon dioxide, etc.) (Table 8).

[0094] Table 8. Completion data and gas logging data for Well L3H

[0095]

[0096]

[0097] 2. Data Cleaning

[0098] The following two types of data are cleaned from single-well gas logging data:

[0099] ①C1+C2+C3+iC4+nC4≧total hydrocarbons;

[0100] ②C1≧All hydrocarbons;

[0101] In the formula, total hydrocarbons, C1, C2, C3, iC4, and nC4 are gas logging data, and C1, C2, C3, iC4, and nC4 represent the contents of methane, ethane, propane, isobutane, and n-butane, respectively.

[0102] 3. Content of gaseous hydrocarbons and

[0103] Calculate the content of gaseous hydrocarbons.

[0104] Formula 1: ∑C 1-4 =C1+C2+C3+iC4+nC4;

[0105] In the formula, ∑C 1-4 The values ​​represent the contents of gaseous hydrocarbons, and C1, C2, C3, iC4, and nC4 represent the contents of methane, ethane, propane, isobutane, and n-butane, respectively.

[0106] The specific results are shown in Table 9 below.

[0107] 4. Liquid hydrocarbon content and

[0108] Calculate the liquid hydrocarbon content.

[0109] Formula 2: ∑C5 + =Total hydrocarbons - ∑C 1-4

[0110] In the formula ∑, C 1-4 For the sum of gaseous hydrocarbon content, ∑C5 + For liquid hydrocarbon content and.

[0111] The specific results are shown in Table 9 below.

[0112] 5. Gas-liquid hydrocarbon coefficient

[0113] The gas-liquid hydrocarbon coefficient is calculated based on the results obtained in steps 4 and 5, using the following formula:

[0114] Formula 3: C 气 / 液 =∑C 1-4 / ∑C5 + ;

[0115] In the formula, C 气 / 液 For gas-liquid hydrocarbon coefficients, ∑C 1-4 For the sum of gaseous hydrocarbon content, ∑C5 + For liquid hydrocarbon content and.

[0116] The specific results are shown in Table 9 below.

[0117] Table 9. Data for calculating gas-liquid hydrocarbon coefficients from gas logging data in the horizontal section of Well L3H.

[0118]

[0119]

[0120] 6. Normalization processing

[0121] Calculation formula: Y = (x - min) / (max - min)

[0122] Y: Normalized data; X: Original data;

[0123] Xmax and Xmin: are the maximum and minimum values ​​of the original dataset, respectively.

[0124] Using the above formula and the data in Table 9, the sum of gaseous hydrocarbon content and sum of liquid hydrocarbon content obtained in steps 3 and 4 are normalized with the gas-liquid hydrocarbon coefficient obtained in step 5. The specific results are shown in Tables 10 and 11 below.

[0125] Table 10 shows the maximum and minimum values ​​of the original dataset processed from Well L3H.

[0126]

[0127] Table 11 Data Calculation and Processing of Gas Logging Data in the Horizontal Section of Well L3H

[0128]

[0129]

[0130] 7. Place the liquid hydrocarbon content from step 6 and the normalized data of the gas-liquid hydrocarbon coefficients on the same coordinate system and display it as a curve, with the vertical axis representing the depth value, as shown below. Figure 5 As shown.

[0131] 8. Based on the liquid hydrocarbon content and gas-liquid hydrocarbon coefficient in the curve obtained in step 7, qualitatively determine the formation oil and gas phase of the horizontal well section of the condensate gas reservoir using the judgment criteria obtained in Example 1.

[0132] The production results of the horizontal well section monitored by tracer in the L3H horizontal well of a certain oil and gas basin are consistent with the phase identification results of this invention, as detailed below. Figure 5 As shown.

[0133] In summary, this invention is a method for predicting the oil and gas phase state of horizontal wells in condensate gas reservoirs using gas logging data. It is applicable to the evaluation and analysis of the oil and gas phase state of formations in new exploration areas, horizontal wells, wells that have not been tested for oil (gas), and wells before fracturing. It can intuitively determine the formation fluid phase state of horizontal well sections in condensate gas reservoirs, divide different phase characteristic segments, and provide a reference for selecting the best gas testing segments, optimizing reservoir stimulation technology, and determining reasonable development methods. It is of great significance for improving gas well productivity, reducing reverse condensate pollution, and improving recovery rate.

[0134] The above description is merely a preferred embodiment of the present invention, but the scope of protection of the present invention is not limited thereto. Any variations or substitutions that can be easily conceived by those skilled in the art within the technical scope disclosed in the embodiments of the present invention should be included within the scope of protection of the present invention. Therefore, the scope of protection of the present invention should be determined by the scope of the claims.

Claims

1. A method for determining the hydrocarbon phase state in a horizontal well section of a condensate gas reservoir, characterized in that: Includes the following steps: (1) Collect continuous gas logging data from a single well in the target area; the data includes total hydrocarbon content and the contents of methane, ethane, propane, isobutane, and n-butane; (2) Based on the data obtained in step (1), calculate the contents of gaseous hydrocarbons and liquid hydrocarbons respectively, and calculate the gas-liquid hydrocarbon coefficient C according to the following formula. 气 / 液 =∑C 1-4 / ∑C5 + , where ∑C 1-4 For the sum of gaseous hydrocarbon content, ∑C5 + For liquid hydrocarbon content and; (3) Normalize the liquid hydrocarbon content and gas-liquid hydrocarbon coefficient obtained in step (2) and correspond them with the actual production capacity of the single well in step (1) to establish a judgment standard for oil and gas phase state, and judge the oil and gas phase state of the horizontal well section according to the judgment standard.

2. The method for determining the hydrocarbon phase state of a horizontal well section in a condensate gas reservoir according to claim 1, characterized in that: The judgment criteria in step (3) are as follows: when the normalized gas-liquid hydrocarbon coefficient is <0.1 and the normalized liquid hydrocarbon content is <0.1, the horizontal well section is a low-yield layer and is not identified; when the normalized gas-liquid hydrocarbon coefficient is >0.1 and the normalized liquid hydrocarbon content is <0.1, the horizontal well section is in the gas phase; when the normalized gas-liquid hydrocarbon coefficient is <0.1 and the normalized liquid hydrocarbon content is >0.1, the horizontal well section is in the liquid phase; when the normalized gas-liquid hydrocarbon coefficient is >0.1 and the normalized liquid hydrocarbon content is >0.1, the horizontal well section is in both gas and liquid phases.

3. The method for determining the oil and gas phase state of a horizontal well section in a condensate gas reservoir according to claim 1 or 2, characterized in that: Step (2) includes data preprocessing; the preprocessing involves removing the following two types of data: The sum of methane content, ethane content, propane content, isobutane content, and n-butane content is greater than or equal to the total hydrocarbon content. Methane content ≥ Total hydrocarbon content.

4. The method for determining the hydrocarbon phase state of a horizontal well section in a condensate gas reservoir according to claim 1 or 2, characterized in that: The gaseous hydrocarbon content and ∑C mentioned in step (2) 1-4 The content of methane, ethane, propane, isobutane, and n-butane.

5. The method for determining the hydrocarbon phase state of a horizontal well section in a condensate gas reservoir according to claim 4, characterized in that: The liquid hydrocarbon content and ∑C5 mentioned in step (2) + This is the difference between the total hydrocarbon content and the sum of the gaseous hydrocarbon content.

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