Method for calculating gas-oil ratio of multistage degassing system of offshore condensate gas reservoir

Abstract

The invention relates to the technical field of oil and gas field development, in particular to a gas-oil ratio calculation method for a multistage degassing system of an offshore condensate gas reservoir, which comprises the following steps: S1, calculating gas components output from a production end to a slug flow trap to obtain volume fractions of a gas phase G1 and a liquid phase L1 under the temperature and pressure conditions; s2, treating the liquid phase L1 through a three-stage separator to obtain a gas phase G4 and a liquid phase L4; s3, combining the gas phase G1 and the gas phase G4, calculating the components of the mixed gas phase, and performing low-temperature dealkylation treatment to obtain a gas phase G2 and a liquid phase L2; s4, mixing a liquid phase L2 obtained after low-temperature dealkylation treatment with a liquid phase L4 obtained after treatment of the three-stage separator, and calculating components of the mixed liquid phase; s5, the gas phase G2 is converted to a compressor, and a new gas phase G3 and a new liquid phase L3 are obtained; and S6, calculating the gas-oil ratio. According to the invention, the condensate oil yield of the condensate gas reservoir can be accurately measured, so that oil tankers with proper tonnage and quantity can be reasonably scheduled for transportation.

Description

Technical Field

[0001] This invention relates to the field of oil and gas field development technology, and more specifically, to a method for calculating the gas-oil ratio in a multi-stage degassing system for offshore condensate gas reservoirs. Background Technology

[0002] Condensate gas reservoirs are a special type of gas reservoir in which hydrocarbons exist as a single gas phase under high temperature and pressure conditions deep underground. When condensate gas is extracted to the surface, the temperature and pressure drop to the surface level, and the formation temperature is usually between the critical temperature and critical condensation temperature of the hydrocarbon mixture, while the pressure is higher than the dew point pressure. During the isothermal depressurization extraction process (the temperature also decreases after the gas reservoir is extracted to the surface, but the effect of pressure reduction is more critical, so theoretically it is approximated as a constant formation temperature), the fluid phase path will cross the dew point line and enter the gas-liquid two-phase region, where some components will condense into liquid petroleum, i.e., condensate oil. This process is called "reverse condensation".

[0003] In condensate gas reservoir development, the fluid undergoes multiple pressure and temperature changes from the well bottom to the surface, resulting in numerous phase transitions and making the calculation of the gas-oil ratio exceptionally complex. Accurately determining condensate oil production is crucial for oil and gas transportation, storage, and sales, especially in offshore development, where precise measurement of condensate oil volume directly affects the rational scheduling of tanker tonnage and quantity, directly impacting transportation costs and operational efficiency.

[0004] Currently, traditional methods such as the black oil model or the simple equilibrium constant method are insufficient to accurately describe the dynamic changes in the composition of the gas and liquid phases during multi-stage separation, and cannot precisely track the distribution of each component. Experimental measurement methods (such as PVT experiments) are also often unable to reliably measure the amount of condensate oil due to limitations in equipment precision and low condensate oil content.

[0005] The shortcomings of the aforementioned existing technologies often lead to large deviations in the prediction of condensate oil volume, which in turn results in unreasonable tanker transportation configurations—too many tankers will significantly increase transportation costs, while too few tankers will fail to complete the transfer of all condensate oil. Summary of the Invention

[0006] The purpose of this invention is to overcome the limitations of existing technologies in accurately measuring the condensate oil production of extracted condensate gas reservoirs, and to provide a method for calculating the gas-oil ratio of a multi-stage degassing system for offshore condensate gas reservoirs. This method can accurately measure the condensate oil production, thereby enabling the rational scheduling of appropriate tonnage and number of tankers for transportation.

[0007] To solve the above-mentioned technical problems, the technical solution adopted by the present invention is as follows: A method for calculating the gas-oil ratio in a multi-stage degassing system for offshore condensate gas reservoirs is provided, including the following steps: S1: Calculate the gas composition output from the production end of the wellbore to the slug trap, and obtain the volume fractions of gas phase G1 and liquid phase L1 under the temperature and pressure conditions, wherein the volume fraction of gas phase G1 is X1 and the volume fraction of liquid phase L1 is Y1. S2: The liquid phase L1 is processed through a three-stage separator to obtain gas phase G4 and liquid phase L4. By calculating the volume fraction of gas phase G4 and liquid phase L4, the volume fraction of gas phase G4 is X4 and the volume fraction of liquid phase L4 is Y4. S3: Mix the gas phase G1 and the gas phase G4 and calculate the composition of the mixed gas phase. Then perform low-temperature dehydrocarbonization treatment to obtain gas phase G2 and liquid phase L2. The volume fraction of gas phase G2 is X2 and the volume fraction of liquid phase L2 is Y2. S4: Mix the liquid phase L2 and the liquid phase L4 and calculate the composition of the mixed liquid phase. After merging under the temperature and pressure conditions at the condensate oil sampling point, calculate the volume fraction of liquid phase L5 as Y5. S5: The gas phase G2 is transferred to the compressor, and under the temperature and pressure conditions after pressurization, a new gas phase G3 and liquid phase L3 are obtained; the volume fraction of gas phase G3 is calculated to be X3. S6: Define the initial gas volume as 1 and calculate the gas-oil ratio using the following formula: ; ; ; In the above formula, Q is the gas phase volume content per unit volume, N is the liquid phase volume content condensed per unit volume, and P is the gas-oil ratio per unit volume.

[0008] In the calculation process of the above scheme, The physical meaning of this is the volume content of gas phase G4 separated by the three-stage separator from a unit of initial gas in step S2. The physical meaning of this expression is the volume fraction of liquid phase L4 separated by the three-stage separator from a unit initial gas in step S2; while The physical meaning is the volume content of the inlet gas before the unit initial volume enters the low-temperature dehydrocarbonization process in step S3. The physical meaning is the gaseous volume content of phase G2 after low-temperature dehydrocarbonization per unit initial volume in step S3; similarly, The physical meaning is the liquid volume content of the liquid phase L2 after low-temperature dehydrogenation per unit initial volume in step S3.

[0009] The final produced gas and liquid both need to be transferred to gas storage tanks or liquid storage tanks for storage. Therefore, the volume fraction in the storage state needs to be multiplied at the end of the formula.

[0010] Furthermore, after calculating the gas composition from the production end to the slug trap using the QNSS model, the gas phase G1 and the liquid phase L1 are obtained after oil-gas separation through the gas path and oil path. The gas phase and liquid phase need to be processed by different processes, so the gas path and oil path need to be set up to separate the condensate oil and gas first.

[0011] Furthermore, in step S1, the temperature and pressure conditions of the gas phase G1 and the liquid phase L1 are 5-10℃ and 10-10.5MPa, respectively; the temperature and pressure conditions inside the slug flow trap are the temperatures at which condensate gas is extracted from underground to the surface for collection and processing.

[0012] Furthermore, in step S4, the temperature and pressure conditions at the condensate oil sampling point are 22.5-27.5℃ and 0.2-0.25Mpa; the temperature and pressure conditions at the condensate oil sampling point are the same as those in actual engineering oil tank storage.

[0013] Furthermore, in step S5, the temperature and pressure conditions after the compressor is boosted are 40-45℃ and 13-17 MPa; the compressor boosting process simulates the gas pressure under storage conditions, at which time liquid phase L3 will condense in the gas storage tank.

[0014] Furthermore, in step S4, the volume fraction of gas phase G5 obtained by calculating at the condensate oil sampling point under the temperature and pressure conditions of the gas phase G4 separated by the three-stage separator is X5. The formula for calculating the volume content of gas phase G5 per unit initial gas is: ; In the above formula, This represents the volume content of gaseous G5 per unit volume.

[0015] In engineering, after the condensate oil is separated by the three-stage separator, it is directly fed into the oil reservoir storage tank. The oil tank is usually required to not contain too much gas. Under the temperature and pressure conditions at the condensate oil sampling point, the volume fraction of gas phase G5 should be close to 0. If the value of X5 deviates too much from zero, the engineer can calculate the gas volume content according to the above formula in order to adjust the storage in the future.

[0016] Furthermore, in step S3, after low-temperature dehydrocarbonization, the formula for calculating the volume of liquid phase L2 obtained per unit initial gas is: ; In step S5, the volume fraction of liquid phase G3 is calculated as Y3. The formula for calculating the volume of liquid phase L3 obtained per unit initial gas after compressor processing is as follows: ; In the above formula, This refers to the volume content of the liquid phase L2 at the outlet after low-temperature dehydrocarbonization. The volume content of the liquid phase L3 obtained after compressor processing.

[0017] In engineering, the gas obtained after low-temperature dehydrocarbonization is relatively pure and can be directly used for pressurized storage. However, the gas tank is usually required to not contain too much liquid. Under the storage temperature and pressure conditions, the volume fraction of liquid phase G3, Y3 should be close to 0, that is, the gas tank will not continue to condense and precipitate liquid condensate. If the value of Y3 deviates too much from zero, the engineering can calculate the volume content of the condensed liquid phase according to the above formula, so as to facilitate the subsequent adjustment and storage of the gas tank.

[0018] Further, in step S3, the mixed gas phase components of gas phase G1 and gas phase G4 are calculated using a weighted summation model; in step S4, the mixed liquid phase components of liquid phase L2 and liquid phase L4 are calculated using a weighted summation model. Based on the principle of the weighted summation mathematical model, the component processed in each step is equal to the weighted sum of the volume fractions of all components before this step, where the weight of each component (the sum of all weights is 1) is the percentage of that component in the total gas volume. Finally, in step S6, the temperature and pressure during gas and liquid phase storage are simulated using a compressor and sampling points to calculate the gas-oil ratio under these physical conditions.

[0019] Furthermore, the weighted summation model is calculated using the following formula: ; in, ; In the above formula, This represents the volume fraction of a specific component in a fluid mixture. This represents the volume fraction of the component in the incoming fluid before mixing. This represents the volume fraction of the influent in the mixed fluid.

[0020] The weighted summation model, based on fundamental statistical principles, can accurately estimate the volume fraction of each component in a gas mixture from different gas paths after mixing.

[0021] Furthermore, in steps S1-S5, the volume fraction is calculated using the QNSS model; the Newton-Raphson iteration formula for calculating the volume fraction using the QNSS model is as follows: ; ; Given the feed composition Zi and the phase equilibrium constant Ki, the Rachford-Rice equation can be solved to obtain... ; In the above formula, This represents the volume fraction of the liquid phase component. This represents the volume fraction of the gaseous component. As feed components, The phase equilibrium constant of the component is... This represents the gas phase fraction. The above calculation formula is the basic theoretical calculation formula for the QNSS model of the steady-state flash evaporation process.

[0022] The Rachford-Rice equation is: In the process of Newton's iterative solution, it is necessary to first assume a set of initial phase equilibrium constants. Calculated by the Rachford-Rice equation This allows for the calculation of the liquid and gas phase compositions, utilizing new... and Recalculate using the state equation Final check If the composition does not converge, try a new one. Perform calculations using the Rachford-Rice equation until... The combination of these two components converges.

[0023] Compared with the prior art, the beneficial effects of the present invention are: 1. Based on this calculation method, in engineering, the composition of condensate gas reservoirs in wellbores on the surface can be measured to calculate the oil flow volume and gas flow volume in advance. This helps engineers to rationally schedule the appropriate tonnage and number of tankers for transportation, reduce transportation costs, and achieve the goal of integrated production, supply and sales in gas reservoir development.

[0024] 2. Based on this calculation method, in engineering practice, by measuring the composition of condensate gas reservoirs in wellbores on the surface, the volume fraction of each component of the mixed gas in different gas paths can be estimated relatively accurately. Attached Figure Description

[0025] Figure 1 A flowchart for calculating the gas-oil ratio in a multi-stage degassing system for offshore condensate gas reservoirs; Figure 2 A schematic diagram illustrating the steps of a method for calculating the gas-oil ratio in a multi-stage degassing system for offshore condensate gas reservoirs. Figure 3 This is a flowchart illustrating the workflow of a method for calculating the gas-oil ratio in a multi-stage degassing system for offshore condensate gas reservoirs. Detailed Implementation

[0026] The present invention will be further described below with reference to specific embodiments. The accompanying drawings are for illustrative purposes only, representing schematic diagrams rather than actual physical objects, and should not be construed as limiting the scope of this patent. To better illustrate the embodiments of the present invention, some components in the drawings may be omitted, enlarged, or reduced, and do not represent the actual dimensions of the product. It is understandable to those skilled in the art that some well-known structures and their descriptions may be omitted in the drawings.

[0027] In the accompanying drawings of the embodiments of the present invention, the same or similar reference numerals correspond to the same or similar components. In the description of the present invention, it should be understood that if terms such as "upper," "lower," "left," "right," etc., indicate the orientation or positional relationship based on the orientation or positional relationship shown in the drawings, they are only for the convenience of describing the present invention and simplifying the description, and do not indicate or imply that the device or element referred to must have a specific orientation, or be constructed and operated in a specific orientation. Therefore, the terms used to describe positional relationships in the drawings are only for illustrative purposes and should not be construed as limiting the present patent. For those skilled in the art, the specific meaning of the above terms can be understood according to the specific circumstances.

[0028] Example 1 This embodiment is the first embodiment of a method for calculating the gas-oil ratio in a multi-stage degassing system for offshore condensate gas reservoirs. Figures 1 to 3 As shown, it includes the following steps: S1: Calculate the gas composition output from the production end of the wellbore to the slug trap, and obtain the volume fractions of gas phase G1 and liquid phase L1 under the temperature and pressure conditions, where the volume fraction of gas phase G1 is X1 and the volume fraction of liquid phase L1 is Y1. S2: The liquid phase L1 is processed through a three-stage separator to obtain gas phase G4 and liquid phase L4. By calculating the volume fraction of gas phase G4 and liquid phase L4, the volume fraction of gas phase G4 is X4 and the volume fraction of liquid phase L4 is Y4. S3: Mix gas phase G1 and gas phase G4 and calculate the composition of the mixed gas phase. Then perform low-temperature dehydrocarbonization treatment to obtain gas phase G2 and liquid phase L2. The volume fraction of gas phase G2 is X2 and the volume fraction of liquid phase L2 is Y2. S4: Mix liquid phase L2 and liquid phase L4 and calculate the composition of the mixed liquid phase. Under the temperature and pressure conditions at the condensate oil sampling point, after merging, calculate the volume fraction of liquid phase L5 as Y5. S5: The gas phase G2 is transferred to the compressor. Under the temperature and pressure conditions after pressurization, a new gas phase G3 and liquid phase L3 are obtained. The volume fraction of gas phase G3 is calculated to be X3. S6: Define the initial gas volume as 1 and calculate the gas-oil ratio using the following formula: ; ; ; In the above formula, Q is the gas phase volume content per unit volume, N is the liquid phase volume content condensed per unit volume, and P is the gas-oil ratio per unit volume.

[0029] Specifically, after calculating the gas composition from the production end to the slug trap using the QNSS model, the gas phase G1 and liquid phase L1 are obtained after oil-gas separation through the gas path and oil path. The gas phase and liquid phase need to be processed by different processes, so the gas path and oil path need to be set up to separate the condensate oil and gas first.

[0030] Specifically, in step S1, the temperature and pressure conditions for the gas phase G1 and liquid phase L1 are 5-10℃ and 10-10.5 MPa, respectively; the temperature and pressure conditions inside the slug trap are the temperatures at which condensate gas is extracted from underground to the surface for collection and processing. In this embodiment, as... Figure 3 As shown, the temperature and pressure conditions for gas phase G1 and liquid phase L1 are 7℃ and 10.3MPa, respectively.

[0031] Specifically, in step S4, the temperature and pressure conditions at the condensate oil sampling point are 22.5-27.5℃ and 0.2-0.25 MPa; the temperature and pressure conditions at the condensate oil sampling point are the same as those during actual oil tank storage in engineering practice. In this embodiment, as... Figure 3 As shown, the temperature and pressure conditions at the condensate oil sampling point were 25℃ and 0.23 MPa.

[0032] Specifically, in step S5, the temperature and pressure conditions after compressor pressurization are 40-45℃ and 13-17 MPa; the compressor pressurization process simulates the gas pressure under storage conditions, at which time liquid phase L3 will condense in the gas storage tank. In this embodiment, as... Figure 3 As shown, the temperature and pressure conditions after the compressor is boosted are 43℃ and 15MPa.

[0033] Specifically, in steps S1-S5, the volume fraction is calculated using the QNSS model; the Newton-Raphson iteration formula for calculating the volume fraction using the QNSS model is: ; ; Given the feed composition Zi and the phase equilibrium constant Ki, the Rachford-Rice equation can be solved to obtain... ; In the above formula, This represents the volume fraction of the liquid phase component. This represents the volume fraction of the gaseous component. As feed components, The phase equilibrium constant of the component is... This represents the gas phase fraction. The above calculation formula is the basic theoretical calculation formula for the QNSS model of the steady-state flash evaporation process.

[0034] The Rachford-Rice equation is: In the process of Newton's iterative solution, it is necessary to first assume a set of initial phase equilibrium constants. Calculated by the Rachford-Rice equation This allows for the calculation of the liquid and gas phase compositions, utilizing new... and Recalculate using the state equation Final check If the composition does not converge, try a new one. Perform calculations using the Rachford-Rice equation until... The combination of these two components converges.

[0035] The calculation principle of the gas-oil ratio calculation method for a multi-stage degassing system in an offshore condensate gas reservoir in this embodiment is as follows: Taking a condensate gas reservoir that was actually exploited as an example, the component data at the wellbore after exploitation (i.e., the wellbore components before entering the slug trap) is shown in Table 1.

[0036]

[0037] Table 1 - Wellbore Component Data (i.e., components before entering the slug trap) Step S1: Perform QNSS model calculations in the process slug trap to obtain the processed gas and liquid phase components (see Table 2), as well as the gas and liquid phase volume fractions (Y1=2.3847, X1=97.6153).

[0038]

[0039] Table 2 - Components after slug flow trap treatment In step S2, the oil phase separated by the slug trap is processed by a three-stage separator. The components entering the three-stage separator are the liquid phase components from step S1. The components calculated by the QNSS model are shown in Table 3, with gas-liquid two-phase volume fractions (Y4=0.0849, X4=99.9151).

[0040]

[0041] Table 3 - Components after treatment by the three-stage separator Step 3: The gas phase separated by the three-stage separator is combined with the gas phase separated by the slug trap. The percentage of each component to be dehydrocarbonized at low temperature after mixing is calculated by a weighted summation model. The calculation results are shown in Table 4.

[0042]

[0043] Table 4 - Weighted summation component data of the mixed gas before low-temperature dehydrocarbonization The QNSS model was used to calculate the above gas phase under low temperature dehydrocarbonization temperature and pressure conditions. The calculated composition is shown in Table 5, and the volume fractions of the gas and liquid phases were obtained (Y2=1.5638, X2=98.4362).

[0044]

[0045] Table 5 - Component data after low-temperature dehydrocarbonization treatment Step S4: The composition before entering the condensate oil sampling point is calculated using a weighted summation model (see Table 6).

[0046] Table 6 - Weighted summation of components after liquid phase mixing at condensate oil sampling points The QNSS model was used to calculate the volume fractions of the gas and liquid phases (Y5=0.6132, X5=99.3868) for the liquid phase.

[0047] Step S5: The gas from the low-temperature dehydrocarbonization process is further pressurized by a compressor in the gas path. The obtained gas is then calculated using the QNSS model to obtain the gas-liquid two-phase volume fraction (Y3=0, X3=100).

[0048] Step S6: Calculate using the established formula: ; We obtain Q = 0.984342071 and N = 9.60144e-05; The gas-oil ratio per unit volume can be obtained This result is basically consistent with the actual measured gas-oil ratio of 10342 on site.

[0049] The beneficial effects of this embodiment are: by measuring the condensate gas reservoir composition in the wellbore on the surface, the calculation of oil volume and gas volume in the pipeline can be realized in advance, which can effectively help engineers to rationally schedule the appropriate tonnage and number of oil tankers for transportation, reduce transportation costs, and achieve the goal of integrated production, supply and sales in gas reservoir development.

[0050] Example 2 This embodiment is the second embodiment of a method for calculating the gas-oil ratio in a multi-stage degassing system for offshore condensate gas reservoirs. Figures 2 to 3As shown, the difference from Embodiment 1 is as follows: Specifically, in step S4, the volume fraction of gas phase G5 obtained from the gas phase G4 separated by the three-stage separator is calculated as X5 under the temperature and pressure conditions at the condensate oil sampling point. The formula for calculating the volume content of gas phase G5 per unit initial gas is: ; In the above formula, This represents the volume content of gaseous G5 per unit volume.

[0051] In engineering, after the condensate oil is separated by the three-stage separator, it is directly fed into the oil reservoir storage tank. The oil tank is usually required to not contain too much gas. Under the temperature and pressure conditions at the condensate oil sampling point, the volume fraction of gas phase G5 should be close to 0. If the value of X5 deviates too much from zero, the engineer can calculate the gas volume content according to the above formula in order to adjust the storage in the future.

[0052] Specifically, in step S3, after low-temperature dehydrocarbonization, the formula for calculating the volume of liquid phase L2 obtained per unit initial gas is: ; In step S5, the volume fraction of liquid phase G3 is calculated as Y3. The formula for calculating the volume of liquid phase L3 obtained per unit initial gas after compressor processing is as follows: ; In the above formula, This refers to the volume content of the liquid phase L2 at the outlet after low-temperature dehydrocarbonization. The volume content of the liquid phase L3 obtained after compressor processing.

[0053] In engineering, the gas obtained after low-temperature dehydrocarbonization is relatively pure and can be directly used for pressurized storage. However, the gas tank is usually required to not contain too much liquid. Under the storage temperature and pressure conditions, the volume fraction of liquid phase G3, Y3 should be close to 0, that is, the gas tank will not continue to condense and precipitate liquid condensate. If the value of Y3 deviates too much from zero, the engineering can calculate the volume content of the condensed liquid phase according to the above formula, so as to facilitate the subsequent adjustment and storage of the gas tank.

[0054] The calculation principle of the gas-oil ratio calculation method for a multi-stage degassing system in an offshore condensate gas reservoir in this embodiment is as follows: Using the above calculation formulas, the volume content of condensate oil in the gas after low-temperature dehydrocarbonization under the storage temperature and pressure conditions, as well as the gas volume content of condensate oil under the temperature and pressure conditions at the sampling point, can be calculated.

[0055] The beneficial effects of this embodiment are: by calculating the volume fraction of liquid phase G3 as Y3 and the volume fraction of gas phase G5 as X5, the volume of gas and liquid phases in the storage process (low-temperature dehydrocarbonization and separation by a three-stage separator) can be accurately calculated, which can effectively help engineers to reasonably manage the storage status of the finished product.

[0056] Example 3 This embodiment is the second embodiment of a method for calculating the gas-oil ratio in a multi-stage degassing system for offshore condensate gas reservoirs. Figure 2 As shown, the difference between Example 1 and Example 2 is as follows: Specifically, in step S3, the mixed gas phase components of gas phase G1 and gas phase G4 are calculated using a weighted summation model; in step S4, the mixed liquid phase components of liquid phase L2 and liquid phase L4 are calculated using a weighted summation model. Based on the principle of the weighted summation mathematical model, the component processed in each step is equal to the weighted sum of the volume fractions of all components before this step, where the weight of each component (the sum of all weights is 1) is the percentage of that component in the total gas volume. Finally, in step S6, the temperature and pressure during gas and liquid phase storage are simulated using a compressor and sampling points to calculate the gas-oil ratio under these physical conditions.

[0057] Specifically, the weighted summation model calculation formula is as follows: ; in, ; In the above formula, This represents the volume fraction of a specific component in a fluid mixture. This represents the volume fraction of the component in the incoming fluid before mixing. This represents the volume fraction of the influent in the mixed fluid.

[0058] The weighted summation model, based on fundamental statistical principles, can accurately estimate the volume fraction of each component in a gas mixture from different gas paths after mixing.

[0059] The calculation principle of the gas-oil ratio calculation method for a multi-stage degassing system in an offshore condensate gas reservoir in this embodiment is as follows: Carbon dioxide in the mixed gas ( For example, in a certain production process, when the two gases are mixed, the gas from the slug trap accounts for approximately 97.372% of the total mixed gas, and the gas from the three-stage separator accounts for approximately 2.683% of the total mixed gas. Based on the data in Tables 2 and 3, the weighted summation model calculates:

[0060] The percentage of carbon dioxide components in Table 3 is obtained.

[0061] The beneficial effects of this embodiment are: through a reasonable mathematical model, the content data of each component of the two mixed gases after mixing can be calculated relatively accurately with small errors.

[0062] In the specific implementation of the above embodiments, the technical features can be combined in any non-contradictory way. For the sake of brevity, not all possible combinations of the above technical features are described. However, as long as the combination of these technical features is not contradictory, it should be considered to be within the scope of this specification.

[0063] Obviously, the above embodiments of the present invention are merely examples for clearly illustrating the present invention, and are not intended to limit the implementation of the present invention. Those skilled in the art can make other variations or modifications based on the above description. It is neither necessary nor possible to exhaustively describe all embodiments here. Any modifications, equivalent substitutions, and improvements made within the spirit and principles of the present invention should be included within the scope of protection of the claims of the present invention.

Claims

1. A method for calculating the gas-oil ratio in a multi-stage degassing system for offshore condensate gas reservoirs, characterized in that, Includes the following steps: S1: Calculate the gas composition output from the production end of the wellbore to the slug trap, and obtain the volume fractions of gas phase G1 and liquid phase L1 under the temperature and pressure conditions, wherein the volume fraction of gas phase G1 is X1 and the volume fraction of liquid phase L1 is Y1. S2: The liquid phase L1 is processed through a three-stage separator to obtain gas phase G4 and liquid phase L4. By calculating the volume fraction of gas phase G4 and liquid phase L4, the volume fraction of gas phase G4 is X4 and the volume fraction of liquid phase L4 is Y4. S3: Mix the gas phase G1 and the gas phase G4 and calculate the composition of the mixed gas phase. Then perform low-temperature dehydrocarbonization treatment to obtain gas phase G2 and liquid phase L2. The volume fraction of gas phase G2 is X2 and the volume fraction of liquid phase L2 is Y2. S4: Mix the liquid phase L2 and the liquid phase L4 and calculate the composition of the mixed liquid phase. After merging under the temperature and pressure conditions at the condensate oil sampling point, calculate the volume fraction of liquid phase L5 as Y5. S5: The gas phase G2 is transferred to the compressor, and under the temperature and pressure conditions after pressurization, a new gas phase G3 and liquid phase L3 are obtained; the volume fraction of gas phase G3 is calculated to be X3. S6: Define the initial gas volume as 1 and calculate the gas-oil ratio using the following formula: ； ； ； In the above formula, Q is the gas phase volume content per unit volume, N is the liquid phase volume content condensed per unit volume, and P is the gas-oil ratio per unit volume.

2. The method for calculating the gas-oil ratio in a multi-stage degassing system for offshore condensate gas reservoirs according to claim 1, characterized in that, After calculating the gas composition output from the wellbore production end to the slug trap, the gas phase G1 and the liquid phase L1 are obtained after oil-gas separation through the gas path and oil path.

3. The method for calculating the gas-oil ratio in a multi-stage degassing system for offshore condensate gas reservoirs according to claim 2, characterized in that, In step S1, the temperature and pressure conditions of the gas phase G1 and the liquid phase L1 are 5-10℃ and 10-10.5Mpa, respectively.

4. The method for calculating the gas-oil ratio in a multi-stage degassing system for offshore condensate gas reservoirs according to claim 2, characterized in that, In step S4, the temperature and pressure conditions at the condensate oil sampling point are 22.5-27.5℃ and 0.2-0.25Mpa.

5. The method for calculating the gas-oil ratio in a multi-stage degassing system for offshore condensate gas reservoirs according to claim 2, characterized in that, In step S5, the temperature and pressure conditions after the compressor is pressurized are 40-45℃ and 13-17 MPa.

6. The method for calculating the gas-oil ratio in a multi-stage degassing system for offshore condensate gas reservoirs according to claim 1, characterized in that, In step S4, the volume fraction of gas phase G5 obtained from the gas phase G4 separated by the three-stage separator is calculated as X5 under the temperature and pressure conditions at the condensate oil sampling point. The formula for calculating the volume fraction of gas phase G5 per unit initial gas is: ； In the above formula, This represents the volume content of gaseous G5 per unit volume.

7. The method for calculating the gas-oil ratio in a multi-stage degassing system for offshore condensate gas reservoirs according to claim 1, characterized in that, In step S3, after low-temperature dehydrocarbonization, the formula for calculating the volume of liquid phase L2 obtained per unit initial gas is: ； In step S5, the volume fraction of liquid phase G3 is calculated as Y3. The formula for calculating the volume of liquid phase L3 obtained per unit initial gas after compressor processing is as follows: ； In the above formula, This refers to the volume content of the liquid phase L2 at the outlet after low-temperature dehydrocarbonization. The volume content of the liquid phase L3 obtained after compressor processing.

8. The method for calculating the gas-oil ratio in a multi-stage degassing system for offshore condensate gas reservoirs according to claim 1, characterized in that, In step S3, the mixed gas phase components of gas phase G1 and gas phase G4 are calculated using a weighted summation model; in step S4, the mixed liquid phase components of liquid phase L2 and liquid phase L4 are calculated using a weighted summation model.

9. The method for calculating the gas-oil ratio in a multi-stage degassing system for offshore condensate gas reservoirs according to claim 8, characterized in that, The formula for the weighted summation model is as follows: ； in, ; In the above formula, This represents the volume fraction of a specific component in a fluid mixture. This represents the volume fraction of the component in the incoming fluid before mixing. This represents the volume fraction of the influent in the mixed fluid.

10. A method for calculating the gas-oil ratio in a multi-stage degassing system for offshore condensate gas reservoirs according to any one of claims 1-9, characterized in that, In steps S1-S5, the volume fraction is calculated using the QNSS model; the Newton-Raphson iteration formula for calculating the volume fraction using the QNSS model is as follows: ； ； Given the feed composition Z i and phase equilibrium constant K i Under the given conditions, the Rachford-Rice equation can be solved to obtain... ; In the above formula, This represents the volume fraction of the liquid phase component. This represents the volume fraction of the gaseous component. As the feed component, Let be the phase equilibrium constant of the component. This represents the gas phase fraction.

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