A method and system for determining closed gas lift intervention timing

Abstract

The application discloses a method and system for determining closed gas lift intervention time, comprising: lowering open tubing to a gas well to be intervened, and collecting liquid accumulation information inside the gas well in real time during gas injection, so as to determine corresponding actual well bottom flow pressure and actual formation pressure at the position of the gas well by using the liquid accumulation information; predicting gas lift start-up pressure when the closed gas lift is intervened at present according to the size of the tubing and the gas well to be intervened, and real-time gas injection parameters, and predicting well bottom flow pressure after the closed gas lift starts; comparing and analyzing the predicted gas lift start-up pressure and the actual formation pressure, and the predicted well bottom flow pressure and the actual well bottom flow pressure respectively, so as to determine whether the present time is the best intervention time of the closed gas lift, wherein the best intervention time is the initial time meeting the conditions that the predicted gas lift start-up pressure is greater than the actual formation pressure, and the predicted well bottom flow pressure is less than the actual well bottom flow pressure. The application realizes accurate determination of the best intervention time of the closed gas lift.

Description

Technical Field

[0001] This invention belongs to the field of oil and gas extraction, and in particular relates to a method and system for determining the timing of closed gas lift intervention. Background Technology

[0002] Gas lift is an important means of maintaining stable production in the mid-to-late stages of gas well drainage, especially suitable for continuous drainage in gas wells with large water volumes, and is currently widely used in shale gas fields. As the overall development of shale gas fields enters the low-pressure stable production period, the adaptability of traditional open gas lift tubing deteriorates, and the bottom hole injection pressure is higher than the formation pressure, causing the accumulated fluid in the wellbore to be forced back into the formation.

[0003] In the process of realizing this invention, the inventors discovered that, in order to further improve the gas lift effect, an effective means employed in the prior art is to use a closed gas lift method, installing a packer at the bottom of the open tubing string and a check valve at the bottom of the tubing, thereby preventing the injection pressure from acting on the formation and increasing the fluid discharge rate. However, the well selection conditions for closed gas lift are still not well understood. Introducing closed gas lift too early faces problems such as the risk of installing the packer under pressure (high pressure), the risk of early sand production burying the check valve, high cost, and high friction without increasing production. On the other hand, introducing closed gas lift too late cannot alleviate the fluid accumulation in the gas well in time, reducing production. Summary of the Invention

[0004] One of the technical problems to be solved by this invention is to provide a method for determining the timing of closed-loop gas lift intervention, comprising: lowering an open tubing into the gas well to be intervened in, and collecting real-time information on the accumulated fluid inside the gas well during the gas injection process, thereby using the accumulated fluid information to determine the corresponding actual bottom hole flowing pressure and the actual formation pressure at the location of the gas well; predicting the gas lift start-up pressure at the current intervention time based on the dimensions of the tubing and the gas well to be intervened in, as well as the real-time gas injection parameters, and predicting the bottom hole flowing pressure after the closed-loop gas lift starts; comparing and analyzing the predicted gas lift start-up pressure with the actual formation pressure, and the predicted bottom hole flowing pressure with the actual bottom hole flowing pressure, respectively, to determine whether the current moment is the optimal intervention time for closed-loop gas lift, wherein the optimal intervention time is the initial moment that satisfies the conditions that the predicted gas lift start-up pressure is greater than the actual formation pressure and the predicted bottom hole flowing pressure is less than the actual bottom hole flowing pressure.

[0005] Preferably, the fluid accumulation information includes the fluid accumulation height in the tubing, the fluid accumulation height in the annulus between the tubing and the wellbore, and the fluid physical properties.

[0006] Preferably, the step of determining the corresponding actual bottom hole flowing pressure using the accumulated fluid information includes: measuring the annular fluid height in real time using an echometer, and based on this, combined with the fluid properties and the wellhead annular pressure, obtaining the actual bottom hole flowing pressure, wherein the actual bottom hole flowing pressure is calculated using the following expression:

[0007] p wf =p c +ρ L gH1

[0008] Where, p wf p represents the actual bottom hole flowing pressure. c ρ represents the wellhead annulus pressure. L H represents the density of the liquid accumulation, H1 represents the height of the liquid accumulation in the annulus, and g represents the acceleration due to gravity.

[0009] Preferably, the method further includes: obtaining the tubing fluid height using the actual bottom hole flowing pressure and the fluid accumulation parameters, combined with the wellhead tubing pressure, wherein the tubing fluid height is calculated using the following expression:

[0010] H2=(p wf -p t ) / ρ L g

[0011] Where H2 represents the height of fluid accumulation in the tubing, p t This indicates the wellhead tubing pressure.

[0012] Preferably, the method further includes: extracting bottom hole flowing pressure measurement data and tubing fluid height measurement data from real-time logging information at the construction site, and calculating the corresponding annular fluid height in combination with the fluid properties; correcting the measured annular fluid height based on the calculated annular fluid height, and then recalculating the actual bottom hole flowing pressure and the tubing fluid height using the corrected annular fluid height, so as to correct the calculated actual bottom hole flowing pressure and the calculated tubing fluid height, thereby determining the optimal intervention time based on the corrected parameters.

[0013] Preferably, the step of determining the actual formation pressure at the location of the gas well includes: calculating the actual formation pressure using a production capacity equation based on the gas production rate in real-time production data and the actual bottom-hole flowing pressure, wherein the production capacity equation is a binomial production capacity equation and the actual formation pressure is calculated using the following expression:

[0014]

[0015] Where, p r The actual formation pressure is represented by A and B, which are coefficients, and q represents the gas production rate. wf This represents the actual bottom hole flowing pressure.

[0016] Preferably, the step of predicting the gas lift start-up pressure during the current closed-loop gas lift intervention includes: predicting the gas lift start-up pressure based on the principle of communicating vessels, using the cross-sectional area of ​​the tubing and the annular cross-sectional area of ​​the gas well to be intervened in, wherein the gas lift start-up pressure is calculated using the following expression:

[0017]

[0018] Where, p s p represents the air lift start-up pressure. t Indicates the wellhead tubing pressure, A a A represents the cross-sectional area of ​​the annulus. t H1 represents the cross-sectional area of ​​the tubing, H2 represents the annular fluid accumulation height, and ρ represents the tubing fluid accumulation height. L denoted by ρ, where ρ represents the density of the liquid, and g represents the acceleration due to gravity.

[0019] Preferably, the step of predicting the bottom hole flowing pressure after the closed gas lift is started includes: generating the bottom hole flowing pressure after the closed gas lift is started based on a two-phase flow model, according to the gas injection rate, production rate, tubing size and the size of the gas well to be intervened, wherein the two-phase flow model adopts the HB model and the production rate includes the liquid production rate and the gas production rate.

[0020] Preferably, the method further includes: when the current moment is determined to be the optimal time for intervention, setting the packer in the annulus at the lower end of the tubing and installing a check valve at the bottom of the tubing, thereby allowing the closed-loop gas lift to be introduced into the gas well to be intervened.

[0021] On the other hand, the present invention also provides a system for determining the timing of closed-loop gas lift intervention. The system includes the following modules: a data monitoring module, which is used to lower an open tubing into the gas well to be intervened in and collect information on the accumulated fluid inside the gas well in real time during the gas injection process, thereby using the accumulated fluid information to determine the corresponding actual bottom hole flowing pressure and the actual formation pressure at the location of the gas well; a data prediction module, which is used to predict the gas lift start-up pressure at the current intervention of closed-loop gas lift based on the size of the tubing and the gas well to be intervened in, as well as the real-time gas injection parameters, and to predict the bottom hole flowing pressure after the closed-loop gas lift starts; and an intervention timing determination module, which is used to compare and analyze the predicted gas lift start-up pressure with the actual formation pressure and the predicted bottom hole flowing pressure with the actual bottom hole flowing pressure, respectively, to determine whether the current moment is the optimal intervention time for closed-loop gas lift, wherein the optimal intervention time is the initial moment that satisfies the conditions that the predicted gas lift start-up pressure is greater than the actual formation pressure and the predicted bottom hole flowing pressure is less than the actual bottom hole flowing pressure.

[0022] Compared with the prior art, one or more embodiments of the above solutions may have the following advantages or beneficial effects:

[0023] This invention proposes a method and system for determining the timing of closed-loop gas lift intervention. The method is based on well logging monitoring techniques commonly used in field well logging, collecting and calculating well logging data relevant to determining the intervention timing in real time during gas injection. Then, the method uses the relevant well logging data to predict the gas lift initiation pressure at the current intervention point, and further predicts the bottomhole flowing pressure after the closed-loop gas lift starts at the predicted initiation pressure. Subsequently, by comparing and analyzing the predicted initiation pressure with the actual formation pressure in the current well logging data, and the predicted bottomhole flowing pressure with the actual bottomhole flowing pressure in the current well logging data, the method determines whether the current moment is the optimal intervention time for the closed-loop gas lift. This invention achieves accurate determination of the intervention timing for closed-loop gas lift. Timely intervention based on the determination results ensures a reduction in bottomhole flowing pressure, effectively preventing the backflow of liquid into the formation and guaranteeing stable or increased gas well production.

[0024] Other features and advantages of the invention will be set forth in the description which follows, and will be apparent in part from the description, or may be learned by practicing the invention. The objects and other advantages of the invention may be realized and obtained by means of the structures particularly pointed out in the description, claims, and drawings. Attached Figure Description

[0025] The accompanying drawings are provided to further illustrate the invention and form part of the specification. They are used in conjunction with the embodiments of the invention to explain the invention and do not constitute a limitation thereof. In the drawings:

[0026] Figure 1 This is a step diagram of a method for determining the timing of closed-loop airlift intervention according to an embodiment of this application.

[0027] Figure 2 This is a schematic diagram of the conventional production tubing and the lowering of the closed gas lift tubing in the method for determining the timing of closed gas lift intervention according to an embodiment of this application.

[0028] Figure 3 This is a block diagram of a system for determining the timing of closed-loop airlift intervention, according to an embodiment of this application. Detailed Implementation

[0029] The embodiments of the present invention will be described in detail below with reference to the accompanying drawings and examples, so that the process of how the present invention uses technical means to solve technical problems and achieve technical effects can be fully understood and implemented accordingly. It should be noted that, as long as there is no conflict, the various embodiments and features in the various embodiments of the present invention can be combined with each other, and the resulting technical solutions are all within the protection scope of the present invention.

[0030] Furthermore, the steps shown in the flowchart in the accompanying drawings can be executed in a computer system such as a set of computer-executable instructions, and although a logical order is shown in the flowchart, in some cases the steps shown or described may be executed in a different order than that shown here.

[0031] Gas lift is an important means of maintaining stable production in the mid-to-late stages of gas well drainage, especially suitable for continuous drainage in gas wells with large water volumes, and is currently widely used in shale gas fields. As the overall development of shale gas fields enters the low-pressure stable production period, the adaptability of traditional open gas lift tubing deteriorates, and the bottom hole injection pressure is higher than the formation pressure, causing the accumulated fluid in the wellbore to be forced back into the formation.

[0032] In the process of realizing this invention, the inventors discovered that, in order to further improve the gas lift effect, an effective means employed in the prior art is to use a closed gas lift method, installing a packer at the bottom of the open tubing string and a check valve at the bottom of the tubing, thereby preventing the injection pressure from acting on the formation and increasing the fluid discharge rate. However, the well selection conditions for closed gas lift are still not well understood. Introducing closed gas lift too early faces problems such as the risk of installing the packer under pressure (high pressure), the risk of early sand production burying the check valve, high cost, and high friction without increasing production. On the other hand, introducing closed gas lift too late cannot alleviate the fluid accumulation in the gas well in time, reducing production.

[0033] Therefore, to address the aforementioned problems, this invention proposes a method and system for determining the timing of closed-loop gas lift intervention. This method utilizes well logging information monitoring techniques commonly used in field logging, collecting and calculating well logging data relevant to determining the timing of closed-loop gas lift intervention in real time during gas injection. Then, the gas lift initiation pressure at the current intervention time is predicted using the relevant well logging data, and further, the bottomhole flowing pressure after the closed-loop gas lift is initiated at the predicted initiation pressure is predicted. Subsequently, by comparing and analyzing the predicted initiation pressure with the actual formation pressure in the current well logging data, and the predicted bottomhole flowing pressure with the actual bottomhole flowing pressure in the current well logging data, the optimal intervention time for closed-loop gas lift is determined based on the analysis results. This invention achieves accurate determination of the timing of closed-loop gas lift intervention. Timely intervention based on the determination results ensures a reduction in bottomhole flowing pressure, effectively preventing the backflow of liquid into the formation and guaranteeing stable or increased gas well production.

[0034] Example 1

[0035] Figure 1 This is a flowchart illustrating the steps of a method for determining the timing of closed-loop gas lift intervention according to an embodiment of this application. See below for reference. Figure 1 This will explain each step of the method.

[0036] like Figure 1As shown, in step S110, open tubing is lowered into the gas well to be injected, and the fluid accumulation information inside the gas well is collected in real time during the gas injection process. This fluid accumulation information is then used to determine the corresponding actual bottomhole flowing pressure and the actual formation pressure at the gas well's location. In this embodiment, open tubing is used for gas injection into the gas well to ensure that, before the downhole conditions of the gas well are fully understood, there is no risk of prematurely intervening in closed gas lift operations, which could lead to the risks of pressurized (high-pressure) packer installation and early sand production burying of the single-flow valve. Furthermore, the frictional resistance experienced by the closed gas lift tubing downhole is greater than that of conventional production tubing, and premature intervention in closed gas lift can also lead to a decrease in production. Therefore, open tubing is first lowered into the gas well to be injected. Then, during the gas injection process, commonly used field logging monitoring methods are employed to collect real-time fluid accumulation information inside the gas well, thereby understanding the real-time fluid accumulation status inside the gas well. Subsequently, by utilizing the accumulated liquid height and physical property information related to determining the intervention time of the closed gas lift, the corresponding actual bottom hole flowing pressure and the actual formation pressure at the location of the gas well are determined. Based on the actual bottom hole flowing pressure and the actual formation pressure, the changes in logging parameters that will occur during the current closed gas lift intervention are predicted.

[0037] In this embodiment, the fluid accumulation information includes the fluid accumulation height in the tubing, the fluid accumulation height in the annulus between the tubing and the wellbore, and fluid property parameters. Specifically, the tubing fluid accumulation height and the fluid accumulation height in the annulus between the tubing and the wellbore are fluid height information relevant to determining the intervention time of the closed-loop gas lift, and the fluid property parameters are fluid property information relevant to determining the intervention time of the closed-loop gas lift.

[0038] The process of determining the corresponding actual bottom hole flowing pressure using accumulated fluid information includes the following steps:

[0039] Step S1 involves using an echometer to measure the annular fluid height in real time. Based on this, combined with the fluid properties and wellhead annular pressure, the actual bottom hole flowing pressure is obtained. In this embodiment, a common field logging monitoring method is used, namely, directly using an echometer to measure the fluid height in the annulus between the tubing and the wellbore. Simultaneously, the wellhead annular pressure and fluid density from the fluid properties are extracted from the real-time logging information measured by relevant logging equipment at the construction site. Then, using the annular fluid height measured by the echometer, and the wellhead annular pressure and fluid density measured by relevant logging equipment, the real-time actual bottom hole flowing pressure is calculated, thereby obtaining the actual bottom hole flowing pressure of this embodiment. The actual bottom hole flowing pressure is calculated using the following expression:

[0040] p wf =p c +ρ L gH1 (1)

[0041] Where, pwf p represents the actual bottom hole flowing pressure. c ρ represents the wellhead annulus pressure. L H represents the density of the liquid accumulation, H1 represents the height of the liquid accumulation in the annulus, and g represents the acceleration due to gravity.

[0042] Step S2 utilizes the actual bottom hole flowing pressure and fluid properties, combined with the wellhead tubing pressure, to obtain the tubing fluid height. Specifically, in this embodiment, the wellhead tubing pressure is extracted from the real-time logging information measured by relevant logging equipment at the construction site. Then, using the actual bottom hole flowing pressure calculated in step S1, the fluid density from the measured fluid properties, and the measured wellhead tubing pressure, the real-time tubing fluid height is calculated, thereby achieving the acquisition of the tubing fluid height in this embodiment. The tubing fluid height is calculated using the following expression:

[0043] H2=(p wf -p t ) / ρ L g (2)

[0044] Where H2 represents the height of fluid accumulation in the tubing, p t This indicates the wellhead tubing pressure.

[0045] In step S3, the real-time logging information measured by the relevant logging equipment at the construction site also includes bottom hole flowing pressure measurement data and tubing fluid height measurement data. Therefore, this embodiment also extracts bottom hole flowing pressure measurement data and tubing fluid height measurement data from the real-time logging information at the construction site, and calculates the corresponding annular fluid height by combining the fluid properties parameters. Then, the measured annular fluid height is corrected based on the calculated annular fluid height, and the actual bottom hole flowing pressure and tubing fluid height are recalculated using the corrected annular fluid height to correct the calculated actual bottom hole flowing pressure and calculated tubing fluid height. Thus, the optimal intervention time is determined based on the corrected parameters.

[0046] Specifically, to improve the accuracy of the closed-loop gas lift intervention timing determination, this embodiment first uses real-time logging information from the construction site to correct the annular fluid height measured by the echometer in step S1. That is, this embodiment extracts bottomhole flowing pressure measurement data and tubing fluid height measurement data from real-time logging information from the construction site, and uses the extracted measurement data and fluid density from the fluid properties to calculate the corresponding annular fluid height. Then, by analyzing and comparing the data differences between the annular fluid height measured in step S1 and the annular fluid height calculated in the current step S3, and determining the causes of these differences, the inaccuracy of the annular fluid height measured in step S1 due to measurement errors and other factors is eliminated, thus correcting the annular fluid height measured in step S1.

[0047] Next, after correcting the annular fluid height obtained by measurement in step S1, the actual bottom hole flowing pressure and tubing fluid height are recalculated using the corrected annular fluid height, following the same method as steps S1 and S2. This yields new actual bottom hole flowing pressure and new tubing fluid height. These new data then replace the original actual bottom hole flowing pressure and tubing fluid height calculated in steps S1 and S2, thus correcting the actual bottom hole flowing pressure and tubing fluid height calculated in steps S1 and S2. Based on the corrected annular fluid height, corrected actual bottom hole flowing pressure, and corrected tubing fluid height, the optimal intervention timing is determined. Therefore, this invention effectively improves the accuracy of intervention timing determination results by correcting the relevant parameters used to determine the timing of closed-loop gas lift intervention.

[0048] In this embodiment, during the calculation of the annular fluid height in step S3, the wellhead annular pressure, bottom hole flowing pressure measurement data, and tubing fluid height measurement data are extracted from the real-time logging information measured by relevant logging equipment at the construction site. These data are then used to calculate the annular fluid height calculation data used to correct the annular fluid height measured by the echometer in step S1. Step S3 calculates the annular fluid height using the following expression:

[0049] H1=(p wf -p c ) / ρ L g (3)

[0050] Furthermore, in the step of determining the actual formation pressure at the location of the gas well, the actual formation pressure is back-calculated using the production capacity equation based on the gas production rate and actual bottom-hole flowing pressure from the real-time production data. In this embodiment, the gas production rate from the real-time production data measured by relevant logging equipment at the construction site is substituted into the production capacity equation along with the corrected actual bottom-hole flowing pressure obtained in step S3 above, to achieve the back-calculation of the actual formation pressure. In a specific embodiment of the application, a binomial production capacity equation is used. It should be noted that the present invention does not impose specific limitations on the selection of the production capacity equation; those skilled in the art can select one based on known logging data. In this embodiment, the actual formation pressure is calculated using the following expression:

[0051]

[0052] Where, p r The actual formation pressure is represented by A and B, which are coefficients, and q represents the gas production.

[0053] In step S120, the gas lift initiation pressure at the current intervention time of the closed gas lift is predicted based on the dimensions of the tubing and the gas well to be intervened in, as well as the real-time gas injection parameters, and the bottom hole flowing pressure after the closed gas lift is initiated is also predicted. Specifically, in this embodiment, the dimensions of the tubing and the gas well to be intervened in, as well as the real-time gas injection parameters, are first obtained from the real-time logging information measured by relevant logging equipment at the construction site. Then, assuming that the current time is the opportune moment for intervention in the closed gas lift, the gas lift initiation pressure at the current intervention time is predicted using the obtained parameters. Next, using the predicted gas lift initiation pressure at the current intervention time, the stable bottom hole flowing pressure after the closed gas lift is initiated at the current initiation pressure is calculated, thereby achieving the prediction of the bottom hole flowing pressure after the closed gas lift is initiated in this embodiment. Accordingly, this invention, by assuming an intervention time and obtaining corresponding prediction parameters, and based on the analysis of the prediction parameters, takes the corresponding assumed intervention time as the optimal intervention time, thereby achieving the determination of the optimal intervention time in this embodiment.

[0054] In the step of predicting the gas lift initiation pressure during the current closed-loop gas lift intervention, based on the principle of communicating vessels, the gas lift initiation pressure is predicted using the cross-sectional area of ​​the tubing and the annulus cross-sectional area of ​​the well to be intervened. In this embodiment, according to the principle of communicating vessels, it is assumed that the current accumulating fluid is stationary relative to the current open tubing and the annulus between the tubing and the wellbore, and that the fluid levels in the tubing and the annulus remain level, that is, it is assumed that the accumulating fluid no longer flows and remains stationary during the current closed-loop gas lift intervention. Under these assumptions, the gas lift initiation pressure at the current moment is calculated using the tubing cross-sectional area, the annulus cross-sectional area of ​​the well to be intervened, the wellhead tubing pressure and accumulating fluid density derived from real-time logging information, and the corrected annulus accumulating fluid height and tubing accumulating fluid height, thereby obtaining the predicted gas lift initiation pressure.

[0055] The air lift start-up pressure is calculated using the following expression:

[0056]

[0057] Where, p s Indicates the air lift start-up pressure, A a A represents the cross-sectional area of ​​the annulus. t This indicates the cross-sectional area of ​​the oil pipe.

[0058] Next, in the step of predicting the bottomhole flowing pressure after the closed-loop gas lift is initiated, based on a two-phase flow model, the bottomhole flowing pressure after the initiation of the closed-loop gas lift is generated according to the gas injection rate, production rate, tubing size, and the size of the gas well to be intervened. The two-phase flow model used is the HB model, and the production rate includes both fluid production and gas production. In this embodiment, the bottomhole flowing pressure after the initiation of the closed-loop gas lift is calculated based on the correlation between the stable bottomhole flowing pressure and parameters such as the total gas volume (the sum of gas production and injection rate in the production rate), the fluid production rate, the tubing cross-sectional area in the tubing size, and the well depth in the size of the gas well to be intervened, as reflected by the commonly used two-phase flow model (oil-water two-phase flow production logging interpretation model) in well logging. In this embodiment, the mature HB model is used as the two-phase flow model. It should be noted that this invention does not specifically limit the selection of the two-phase flow model; those skilled in the art can choose a logging interpretation model that reflects the aforementioned correlations to calculate the bottomhole flowing pressure after the initiation of the closed-loop gas lift according to actual needs.

[0059] In step S130, the predicted gas lift start-up pressure is compared with the actual formation pressure, and the predicted bottomhole flowing pressure is compared with the actual bottomhole flowing pressure to determine whether the current moment is the optimal time for closed-loop gas lift intervention. The optimal intervention moment is the initial moment when the predicted gas lift start-up pressure is greater than the actual formation pressure and the predicted bottomhole flowing pressure is less than the actual bottomhole flowing pressure. Specifically, this embodiment first compares the predicted gas lift start-up pressure with the actual formation pressure, and decides whether to continue comparing the predicted bottomhole flowing pressure with the actual bottomhole flowing pressure based on the analysis results. Then, after comparing the predicted bottomhole flowing pressure with the actual bottomhole flowing pressure, it determines whether the current moment is the optimal time for closed-loop gas lift intervention. The optimal intervention moment is the initial moment when the predicted gas lift start-up pressure is greater than the actual formation pressure and the predicted bottomhole flowing pressure is less than the actual bottomhole flowing pressure. That is, if the predicted gas lift start-up pressure is less than the actual formation pressure, it is determined that closed-loop gas lift will not be used; otherwise, the comparison of the predicted bottomhole flowing pressure with the actual bottomhole flowing pressure continues. Subsequently, if the predicted bottomhole flowing pressure is greater than the actual bottomhole flowing pressure, it is determined that closed gas lift will not be used. Otherwise, the initial moment when the predicted gas lift start-up pressure is greater than the actual formation pressure and the predicted bottomhole flowing pressure is less than the actual bottomhole flowing pressure will be taken as the optimal intervention time for closed gas lift.

[0060] When the current moment is determined to be the optimal time for intervention, the packer is placed in the annulus at the lower end of the tubing, and a check valve is installed at the bottom of the tubing, thereby enabling closed-loop gas lift to be introduced into the gas well to be intervened. Figure 2 This is a schematic diagram of the conventional production tubing and the lowering of the closed-loop gas lift tubing in the method for determining the timing of closed-loop gas lift intervention according to an embodiment of this application. In this embodiment, the following is used in the early stage of gas injection: Figure 2 The conventional production tubing shown is used for gas injection. When the optimal intervention time is determined, a packer is directly placed in the annulus at the lower end of the tubing of the conventional production tubing to seal the accumulated fluid in the annulus. A check valve is then installed at the bottom of the tubing, thereby achieving the purpose of introducing closed-loop gas lift into the well to be intervened in. This invention eliminates the need to remove the conventional production tubing when intervening in closed-loop gas lift; it simply converts the conventional production tubing into a closed-loop gas lift tubing during the gas injection process. In other words, the intervention of closed-loop gas lift does not interrupt the gas injection process. Therefore, this invention effectively improves gas injection efficiency.

[0061] Example 2

[0062] Based on the method for determining the timing of closed-loop gas lift intervention described in Embodiment 1 above, this embodiment of the invention also provides a system for determining the timing of closed-loop gas lift intervention.

[0063] Figure 3 This is a block diagram of a system for determining the timing of closed-loop gas lift intervention, according to an embodiment of this application. Figure 3 As shown, the system for determining the timing of closed-loop airlift intervention in this embodiment of the invention includes: a data monitoring module 30, a data prediction module 31, and an intervention timing determination module 32. Specifically, the data monitoring module 30, implemented according to the method described in step S110 above, is configured to lower the open tubing into the gas well to be intervened in, and collect the liquid accumulation information inside the gas well in real time during the gas injection process, thereby using the liquid accumulation information to determine the corresponding actual bottom hole flowing pressure and the actual formation pressure at the location of the gas well; the data prediction module 31, implemented according to the method described in step S120 above, is configured to predict the gas lift start-up pressure when the closed gas lift is intervened in, and predict the bottom hole flowing pressure after the closed gas lift is started, based on the size of the tubing and the gas well to be intervened in, as well as the real-time gas injection parameters; the intervention timing determination module 32, implemented according to the method described in step S130 above, is configured to compare and analyze the predicted gas lift start-up pressure with the actual formation pressure, and the predicted bottom hole flowing pressure with the actual bottom hole flowing pressure, respectively, to determine whether the current moment is the optimal intervention time for the closed gas lift, wherein the optimal intervention time is the initial moment that satisfies the conditions that the predicted gas lift start-up pressure is greater than the actual formation pressure and the predicted bottom hole flowing pressure is less than the actual bottom hole flowing pressure.

[0064] This invention proposes a method and system for determining the timing of closed-loop gas lift intervention. The method is based on commonly used field logging monitoring techniques, collecting and calculating logging data relevant to determining the intervention timing in real time during gas injection. Then, the gas lift initiation pressure at the current intervention time is predicted using the relevant logging data, and further, the bottomhole flowing pressure after the closed-loop gas lift starts at the predicted initiation pressure is predicted. Subsequently, by comparing and analyzing the predicted initiation pressure with the actual formation pressure in the current logging data, and the predicted bottomhole flowing pressure with the actual bottomhole flowing pressure in the current logging data, the optimal intervention time for the closed-loop gas lift is determined based on the analysis results. This invention can achieve accurate and rapid determination of the intervention timing for closed-loop gas lift using existing conventional monitoring methods, demonstrating strong feasibility. Timely intervention based on the determination results can ensure a reduction in bottomhole flowing pressure during the gas lift, effectively preventing the backflow of liquid into the formation and ensuring stable or increased gas well production.

[0065] The above description is merely a specific implementation example of the present invention, and the scope of protection of the present invention is not limited thereto. Any modifications or substitutions made to the present invention by those skilled in the art within the technical specifications described herein should be within the scope of protection of the present invention.

[0066] Of course, the present invention may have other various embodiments. Without departing from the spirit and essence of the present invention, those skilled in the art can make various corresponding changes and modifications according to the present invention, but these corresponding changes and modifications should all fall within the protection scope of the claims of the present invention.

[0067] Those skilled in the art will understand that the modules or steps of the present invention described above can be implemented using general-purpose computing devices. They can be centralized on a single computing device or distributed across a network of multiple computing devices. Optionally, they can be implemented using computer-executable program code, thereby storing them in a storage device for execution by a computing device, or fabricating them separately as individual integrated circuit modules, or fabricating multiple modules or steps as a single integrated circuit module. Thus, the present invention is not limited to any particular hardware and software combination.

[0068] While the embodiments disclosed in this invention are as described above, the content is merely for the purpose of facilitating understanding of the invention and is not intended to limit the invention. Any person skilled in the art to which this invention pertains may make any modifications and variations in form and detail of the implementation without departing from the spirit and scope disclosed herein; however, the scope of patent protection for this invention shall still be determined by the scope defined in the appended claims.

Claims

1. A method for determining the timing of closed-loop gas lift intervention, characterized in that, include: The open tubing is lowered into the gas well to be injected, and the liquid accumulation information inside the gas well is collected in real time during the gas injection process. The liquid accumulation information is then used to determine the corresponding actual bottom hole flowing pressure and the actual formation pressure at the location of the gas well. Based on the dimensions of the tubing and the gas well to be intervened in, as well as the real-time gas injection parameters, the gas lift start-up pressure during the current intervention of closed gas lift is predicted, and the bottom hole flowing pressure after the closed gas lift is started is predicted. The predicted gas lift start-up pressure is compared and analyzed with the actual formation pressure, and the predicted bottom hole pressure is compared and analyzed with the actual bottom hole pressure, so as to determine whether the current moment is the optimal intervention time for closed gas lift. The optimal intervention time is the initial moment when the predicted gas lift start-up pressure is greater than the actual formation pressure and the predicted bottom hole pressure is less than the actual bottom hole pressure.

2. The method according to claim 1, characterized in that, The fluid accumulation information includes the fluid accumulation height in the tubing, the fluid accumulation height in the annulus between the tubing and the wellbore, and the fluid physical properties.

3. The method according to claim 2, characterized in that, The step of determining the corresponding actual bottom hole flowing pressure using the accumulated fluid information includes: The annular fluid height is measured in real time using an echometer. Based on this, combined with the fluid properties and the wellhead annular pressure, the actual bottom hole flowing pressure is obtained. The actual bottom hole flowing pressure is calculated using the following expression: in, This represents the actual bottom hole flowing pressure. Indicates the wellhead annulus pressure. Indicates the density of the liquid. Indicates the height of the annular fluid accumulation. g It represents the acceleration due to gravity.

4. The method according to claim 3, characterized in that, The method further includes: The fluid accumulation height in the tubing is obtained by using the actual bottom hole flowing pressure and the fluid accumulation properties, combined with the wellhead tubing pressure. The fluid accumulation height in the tubing is calculated using the following expression: in, Indicates the height of fluid accumulation in the oil pipe. This indicates the wellhead tubing pressure.

5. The method according to claim 4, characterized in that, The method further includes: Extract bottom hole flowing pressure measurement data and tubing fluid accumulation height measurement data from real-time logging information at the construction site, and calculate the corresponding annular fluid accumulation height by combining the fluid accumulation physical property parameters. The measured annular fluid height is corrected based on the calculated annular fluid height. Then, the actual bottom hole flowing pressure and the tubing fluid height are recalculated using the corrected annular fluid height to correct the calculated actual bottom hole flowing pressure and the calculated tubing fluid height. Based on the corrected parameters, the optimal intervention time is determined.

6. The method according to any one of claims 1 to 5, characterized in that, The steps for determining the actual formation pressure at the location of a gas well include: Based on the gas production data in the real-time production data and the actual bottom hole flowing pressure, the actual formation pressure is inversely calculated using the production capacity equation. The production capacity equation is a binomial production capacity equation, and the actual formation pressure is calculated using the following expression: in, Indicates actual formation pressure. A and B They represent coefficients, Indicates gas production. This represents the actual bottom hole flowing pressure.

7. The method according to claims 1 to 5, characterized in that, The steps for predicting the gas lift start-up pressure during current closed-loop gas lift operations include: Based on the principle of communicating vessels, the gas lift start-up pressure is predicted using the cross-sectional area of ​​the tubing and the annular cross-sectional area of ​​the gas well to be intervened in. The gas lift start-up pressure is calculated using the following expression: in, Indicates the air lift start-up pressure. Indicates the wellhead tubing pressure. Represents the cross-sectional area of ​​the annulus. This represents the cross-sectional area of ​​the oil pipe. Indicates the height of the annular fluid accumulation. Indicates the height of fluid accumulation in the oil pipe. Indicates the density of the liquid. g It represents the acceleration due to gravity.

8. The method according to claims 1-5, characterized in that, The steps for predicting the bottom hole flowing pressure after the start of closed gas lift include: Based on the two-phase flow model, the bottom hole flowing pressure after the closed gas lift is generated according to the gas injection rate, production rate, tubing size, and the size of the gas well to be intervened in. The production rate includes the liquid production rate and the gas production rate.

9. The method according to claims 1-5, characterized in that, The method further includes: When the current moment is determined to be the optimal time for intervention, the packer is placed in the annulus at the lower end of the tubing, and a check valve is installed at the bottom of the tubing, thereby allowing the closed-loop gas lift to be introduced into the gas well to be intervened.

10. A system for determining the timing of closed-loop gas lift intervention, characterized in that, The system includes the following modules: The data monitoring module is used to lower the open tubing into the gas well to be injected and to collect the liquid accumulation information inside the gas well in real time during the gas injection process, thereby using the liquid accumulation information to determine the corresponding actual bottom hole flowing pressure and the actual formation pressure at the location of the gas well. The data prediction module is used to predict the gas lift start-up pressure during the current intervention of closed gas lift based on the size of the tubing and the gas well to be intervened in, as well as the real-time gas injection parameters, and to predict the bottom hole flowing pressure after the closed gas lift is started. The intervention timing determination module is used to compare and analyze the predicted gas lift start-up pressure with the actual formation pressure and the predicted bottom hole flowing pressure with the actual bottom hole flowing pressure, respectively, so as to determine whether the current moment is the optimal intervention time for closed gas lift. The optimal intervention time is the initial moment that satisfies the conditions that the predicted gas lift start-up pressure is greater than the actual formation pressure and the predicted bottom hole flowing pressure is less than the actual bottom hole flowing pressure.

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