A method for evaluating water production in ultra-high pressure, low-permeability gas reservoirs

Abstract

This application relates to a method for evaluating water production in ultra-high pressure, low-permeability gas reservoirs. The steps include first saturating core samples with different gas permeabilities with formation water and conducting nuclear magnetic resonance (NMR) experiments after displacement under different pressure differentials. Based on the obtained first and second NMR T2 spectra, a reservoir bound water saturation prediction model is established, and the experimental pressure gradient of the test well section is obtained. Finally, the reservoir generated movable water saturation in the test well section under the test pressure differential is calculated based on the bound water saturation prediction model and the experimental pressure gradient. The condensate content in the test well section under the test conditions is also calculated based on the condensate content prediction model. The method provided in this application can quantify the type and content of produced water in ultra-high pressure, low-permeability gas reservoirs, considering the influence of reservoir properties and displacement pressure differentials. It provides experimental support for the analysis of water production mechanisms and rational gas production allocation in ultra-high pressure, low-permeability gas reservoirs, demonstrating high reliability and accuracy.

Description

Technical Field

[0001] This application relates to the field of natural gas extraction technology, and in particular to a method for evaluating water production in ultra-high pressure, low-permeability gas reservoirs. Background Technology

[0002] Currently, ultra-high pressure gas reservoirs have a large pressure coefficient and strong natural energy. During the production process, the gas production can be increased by amplifying the production pressure difference. However, low-permeability gas reservoirs have a high initial water saturation due to the constraints of reservoir micropore throat conditions and the limitation of reservoir charging pressure. As the production pressure difference increases, reservoir water production may occur, and the larger the production pressure difference, the more serious the reservoir water production will be. Reservoir water production will lead to a decrease in the gas production of ultra-high pressure gas reservoirs.

[0003] Meanwhile, the CO2 content in natural gas and the reservoir pressure have a significant impact on the condensate water content carried in the produced gas. Therefore, for ultra-high pressure and low permeability gas reservoirs without edge or bottom water intrusion, determining the reservoir produced water type (mobile water, condensate water) and content is crucial, as it is an important basis for understanding the water production mechanism of ultra-high pressure and low permeability gas reservoirs and for rational gas production allocation during the development process.

[0004] In related technologies, the determination of reservoir-generated movable water is mainly achieved through two methods: the semi-permeable partition method and the nuclear magnetic resonance method. The maximum capillary pressure of the semi-permeable partition method is relatively small (generally 1.2 MPa), while the nuclear magnetic resonance method is obtained under a relatively small separation pressure, which is difficult to meet the experimental requirements for the study of reservoir water production in ultra-high pressure gas reservoirs. Summary of the Invention

[0005] This application provides a method for evaluating water production in ultra-high pressure, low-permeability gas reservoirs, in order to solve the problem that conventional water production evaluation methods in related technologies do not consider the environmental characteristics of ultra-high pressure gas reservoirs, resulting in the inability to accurately predict the type and content of water production in ultra-high pressure, low-permeability gas reservoirs without edge and bottom water intrusion.

[0006] This application provides a method for evaluating water production in ultra-high pressure, low-permeability gas reservoirs, the steps of which include:

[0007] Establish a prediction model for condensate water content;

[0008] Cores with different gas permeability were saturated with formation water and subjected to nuclear magnetic resonance experiments to obtain the first nuclear magnetic resonance T2 spectrum. Cores with different gas permeability were subjected to nuclear magnetic resonance experiments after being displaced by different displacement pressure differentials to obtain the second nuclear magnetic resonance T2 spectrum. A reservoir bound water saturation prediction model was established based on the first and second nuclear magnetic resonance T2 spectra.

[0009] Obtain the experimental pressure gradient of the corresponding test well section, calculate the reservoir generated movable water saturation of the test well section under the corresponding test pressure difference based on the reservoir bound water saturation prediction model and the experimental pressure gradient, and calculate the condensate content of the test well section under the corresponding test conditions based on the condensate content prediction model.

[0010] In some embodiments, establishing the condensate water content prediction model includes:

[0011] Natural gas with different CO2 contents was prepared, and the natural gas with different CO2 contents was mixed with formation water under different pressures;

[0012] A preset volume of natural gas is released under a corresponding pressure to obtain the mass of condensate water condensed during the gas release process;

[0013] Based on the mass of condensate water condensed when natural gas with different CO2 contents is released under different pressures, a condensate water content prediction model is established.

[0014] In some embodiments, saturating cores with different gas permeability with formation water includes:

[0015] Physical property tests were conducted on multiple core samples to screen out core samples with different gas permeability.

[0016] The screened core samples were washed, dried, and then vacuum-treated.

[0017] The treated core samples were saturated with formation water.

[0018] In some embodiments, the step of conducting nuclear magnetic resonance experiments on cores with different gas permeability after displacement under different displacement pressure differentials includes:

[0019] Set a displacement pressure differential for the core displacement device;

[0020] Nitrogen gas is introduced into the inlet of the core displacement device to displace the formation water in the core until the water stops flowing out of the outlet of the core displacement device, and the second nuclear magnetic resonance T2 spectrum of the core is obtained under the displacement pressure difference.

[0021] Repeat the above operations by changing the displacement pressure differential or replacing the core with one that has a different gas permeability.

[0022] In some embodiments, establishing a reservoir bound water saturation prediction model based on the first and second NMR T2 spectra includes:

[0023] Based on the first and second nuclear magnetic resonance T2 spectra, the distribution of mobile fluid saturation of cores with different gas permeability under different displacement pressure gradients was obtained.

[0024] Based on the distribution map of movable fluid saturation of cores with different gas permeability under different displacement pressure gradients, the distribution map of bound water saturation of cores with different gas permeability under different displacement pressure gradients is obtained.

[0025] Based on the distribution map of bound water saturation of core samples with different gas permeability under different displacement pressure gradients, a prediction model for bound water saturation in the reservoir is established.

[0026] In some embodiments, obtaining the distribution map of bound water saturation of cores with different gas permeability under different displacement pressure gradients based on the distribution map of mobile fluid saturation of cores with different gas permeability under different displacement pressure gradients includes:

[0027] Based on the distribution diagram of movable fluid saturation of cores with different gas permeability under different displacement pressure gradients, the bound water saturation of cores with different gas permeability under different displacement pressure gradients is calculated.

[0028] By fitting the bound water saturation of core samples with corresponding gas permeability to the corresponding displacement pressure gradient, several corresponding prediction formulas were obtained.

[0029] The bound water saturation of the core samples for gas permeability measurements under different displacement pressure gradients is calculated according to the corresponding prediction formulas.

[0030] Based on the calculated bound water saturation of core samples with different gas permeability under different displacement pressure gradients, the distribution map of bound water saturation of core samples with different gas permeability under different displacement pressure gradients is obtained.

[0031] In some embodiments, obtaining the experimental pressure gradient of the corresponding test well section includes:

[0032] The initial formation pressure, bottom hole flowing pressure, single well control distance, and wellbore radius, as well as the corresponding core length, are obtained for the corresponding test well sections.

[0033] The pressure at the outlet end of the core holder corresponding to the test well section is calculated using the initial formation pressure, bottom hole flowing pressure, single well control distance, wellbore radius, and core length.

[0034] The experimental pressure gradient corresponding to the test well section is calculated using the pressure at the outlet end of the core holder, the pressure at the inlet end of the core holder, and the core length.

[0035] In some embodiments, calculating the reservoir's intrinsic movable water saturation at the corresponding test pressure differential in the test well section based on the reservoir bound water saturation prediction model and the experimental pressure gradient includes:

[0036] Based on the reservoir bound water saturation prediction model and the experimental pressure gradient, a reservoir bound water saturation curve corresponding to the experimental pressure gradient is generated.

[0037] By combining the initial water saturation, gas permeability, and porosity of the corresponding test well section with the reservoir bound water saturation curve, the reservoir innate movable water saturation of the test well section under the corresponding test pressure difference is calculated.

[0038] In some embodiments, the condensate content of the test well section under corresponding test conditions is calculated according to the condensate content prediction model, including:

[0039] Obtain the CO2 content, atmospheric pressure, and wellhead pressure in the natural gas of the corresponding test well section;

[0040] The condensate content of the test well section is calculated based on the CO2 content in the natural gas, atmospheric pressure, and wellhead pressure.

[0041] In some embodiments, the physical property tests include core length, diameter, porosity, and gas permeability.

[0042] The beneficial effects of the technical solution provided in this application include:

[0043] This application provides a method for evaluating water production in ultra-high pressure, low-permeability gas reservoirs. By saturating core samples with different gas permeability with formation water and conducting nuclear magnetic resonance (NMR) experiments after displacement under different pressure differentials, and establishing a reservoir bound water saturation prediction model based on the obtained first and second NMR T2 spectra, and then obtaining the experimental pressure gradient of the corresponding test well section, this method calculates the reservoir's generated movable water saturation under the corresponding test pressure differential based on the bound water saturation prediction model and the experimental pressure gradient. Furthermore, it calculates the condensate water content of the test well section under the corresponding test conditions based on the condensate water content prediction model. Therefore, this method can quantify the type and content of produced water in ultra-high pressure, low-permeability gas reservoirs, considering the influence of reservoir properties and displacement pressure differentials. It provides experimental support for the analysis of water production mechanisms and rational gas production allocation in ultra-high pressure, low-permeability gas reservoirs, demonstrating high reliability and accuracy. Attached Figure Description

[0044] To more clearly illustrate the technical solutions in the embodiments of this application, the accompanying drawings used in the description of the embodiments will be briefly introduced below. Obviously, the accompanying drawings described below are only some embodiments of this application. For those skilled in the art, other drawings can be obtained based on these drawings without creative effort.

[0045] Figure 1 A flowchart illustrating the method for evaluating water production in ultra-high pressure, low-permeability gas reservoirs provided in this application embodiment;

[0046] Figure 2 A graph showing the variation of condensate water content in natural gas with different CO2 contents under different pressures in the ultra-high pressure, low permeability gas reservoir water production evaluation method provided in this application embodiment;

[0047] Figure 3 A graph showing the fitting results of condensate water content in the ultra-high pressure, low permeability gas reservoir water production evaluation method provided in the embodiments of this application;

[0048] Figure 4 Nuclear magnetic resonance (NMR) results under different displacement pressure differentials for the ultra-high pressure, low permeability gas reservoir water production evaluation method provided in the embodiments of this application;

[0049] Figure 5 Distribution of movable fluid saturation in cores with different gas permeability under different displacement pressure gradients for the water production evaluation method of ultra-high pressure low permeability gas reservoirs provided in this application embodiment;

[0050] Figure 6 A graph showing the relationship between bound water saturation and different displacement pressure gradients for different core samples of the ultra-high pressure, low permeability gas reservoir water production evaluation method provided in the embodiments of this application.

[0051] Figure 7 Figure 1. Fitting results of the reservoir bound water saturation considering the reservoir properties and displacement pressure difference in the water production evaluation method for ultra-high pressure and low permeability gas reservoirs provided in the embodiments of this application.

[0052] Figure 8 This is a schematic diagram of the reservoir bound water saturation prediction chart for the ultra-high pressure, low permeability gas reservoir water production evaluation method provided in the embodiments of this application. Detailed Implementation

[0053] To make the objectives, technical solutions, and advantages of the embodiments of this application clearer, the technical solutions of the embodiments of this application will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only some embodiments of this application, not all embodiments. Based on the embodiments of this application, all other embodiments obtained by those skilled in the art without creative effort are within the scope of protection of this application.

[0054] This application provides a method for evaluating water production in ultra-high pressure, low-permeability gas reservoirs. This method solves the problem that conventional water production evaluation methods in related technologies do not consider the environmental characteristics of ultra-high pressure gas reservoirs, resulting in the inability to accurately predict the type and content of water production in ultra-high pressure, low-permeability gas reservoirs without edge or bottom water intrusion.

[0055] See Figure 1As shown, this method first requires establishing a condensate water content prediction model. Core samples with different gas permeability are saturated with formation water and subjected to nuclear magnetic resonance (NMR) experiments to obtain the first NMR T2 spectrum. Core samples with different gas permeability are then subjected to NMR experiments after displacement under different displacement pressure differentials to obtain the second NMR T2 spectrum. Based on the first and second NMR T2 spectra, a reservoir bound water saturation prediction model is established, and the experimental pressure gradient of the corresponding test well section is obtained. The reservoir generated movable water saturation of the test well section under the corresponding test pressure differential is calculated based on the reservoir bound water saturation prediction model and the experimental pressure gradient. Finally, the condensate water content of the test well section under the corresponding test conditions is calculated based on the condensate water content prediction model. This method can quantify the type and content of produced water in ultra-high pressure, low-permeability gas reservoirs, considering the influence of reservoir properties and displacement pressure differentials. It provides experimental support for the analysis of water production mechanisms and rational gas production allocation in ultra-high pressure, low-permeability gas reservoirs, demonstrating high reliability and accuracy.

[0056] Furthermore, the specific steps for establishing a condensate water content prediction model include:

[0057] Natural gas with different CO2 contents was prepared, and the natural gas with different CO2 contents was mixed with formation water under different pressures;

[0058] A preset volume of natural gas is released under a corresponding pressure to obtain the mass of condensate water condensed during the gas release process;

[0059] Based on the mass of condensate water condensed when natural gas with different CO2 contents is released under different pressures, a condensate water content prediction model is established.

[0060] Specifically, when preparing natural gas samples with different CO2 contents, multiple natural gas samples 1 were obtained based on the average hydrocarbon gas composition content of each well in the region. Different concentrations of CO2 were then introduced into each natural gas sample 1 to obtain multiple natural gas samples with different CO2 contents. Chromatographic analysis was performed on the gas samples to determine the accuracy of the gas composition. Taking four natural gas samples as an example, natural gas samples 1 to 4 were obtained for the experiment. The detailed composition of natural gas samples 1 to 4 is shown in Table 1. Natural gas samples 1 to 4 were saturated with formation water, and gas volumes were released at different constant pressures. The released gas was then collected by condensers to remove water from the gas.

[0061] Table 1. Components of natural gas samples 1–4

[0062]

[0063] After obtaining multiple samples of natural gas with different CO2 contents, the condensate water content in the natural gas under different pressure conditions was obtained using the condensation method. Taking a constant pressure of 90 MPa as an example, the specific experimental steps are as follows:

[0064] First, check the airtightness of each instrument. After checking, transfer one of the prepared natural gas samples into the experimental apparatus, along with excess formation water. Raise the temperature to 190℃ and the pressure to 90MPa, and stir continuously for about 6 hours until the system pressure stabilizes. Set the high-pressure displacement pump to constant pressure mode, retract the piston of the high-pressure displacement pump to the initial position, and record the initial reading of the gas meter and the initial mass of the condensate collection bottle. Open the valve at the top of the experimental apparatus, maintaining the pressure while slowly releasing about 1000 cm³ of gas. 3 High-pressure gas; close the top valve, read the final reading of the gas meter, and weigh the final mass of the liquid collection bottle. Calculate the mass of the condensate collected in the liquid collection bottle, and then calculate the water content in the natural gas sample in this experiment based on the mass of the condensate. Here, content generally refers to volume percentage. The formula for calculating the condensate content E in the natural gas sample is as follows:

[0065]

[0066] Where, ρ w V is the density of formation water. g For gas meter reading, m t Let m be the final mass of the liquid collection bottle and m0 be the initial mass of the liquid collection bottle.

[0067] Specifically, the rated operating temperature of the above-mentioned experimental apparatus is greater than or equal to 200℃, the temperature control accuracy is less than 0.5℃, the rated operating pressure is greater than or equal to 150MPa, and the capacity of the gas meter is greater than or equal to 1000cm³. 3 The minimum scale resolution is less than or equal to 1 cm. 3 The changes in condensate water content of natural gas samples 1 to 4 under different constant pressure conditions were obtained through experiments. See [link to details]. Figure 2 As shown, Figure 2 The x-axis represents the experimental pressure, and the y-axis represents the condensate water content in natural gas with different CO2 contents. Figure 2 Analysis shows that the condensate content increases continuously with decreasing pressure and increasing CO2 content. Pressure and CO2 content are the main factors affecting the condensate content in natural gas. A predictive model for condensate content in natural gas was established by analyzing and fitting experimental data. (See details...) Figure 3 As shown, the fitting formula is as follows:

[0068]

[0069] in, Here, E represents the effect of CO2 content and pressure, E represents the water content in the gas sample, i.e., the condensate water content in the natural gas, and C represents the CO2 content. CO2 P represents the CO2 content in natural gas, and P is the experimental pressure. a Atmospheric pressure.

[0070] Furthermore, core samples with different gas permeability were saturated with formation water. The specific steps included first conducting physical property tests on multiple core samples to screen out those with different gas permeability, then washing and drying the screened core samples, followed by vacuum treatment, and finally saturating the treated core samples with formation water.

[0071] Specifically, physical property tests include core length, diameter, porosity, and gas permeability. Therefore, cores with different gas permeability are screened out through physical property tests. Nuclear magnetic resonance (NMR) technology can quickly, non-destructively, and accurately determine the saturation of mobile fluids in core samples. Therefore, in order to quantify the saturation of mobile fluids in ultra-high pressure, low-permeability gas reservoirs under different displacement pressure differentials, and further quantitatively analyze the influence of different displacement pressure differentials on reservoir mobile water, representative core samples with different gas permeability within the region are screened out as shown in Table 2.

[0072] Table 2 Core Sample Parameters

[0073] Core number Length / cm Diameter / cm Porosity / % <![CDATA[Gas permeability / 10 -3 μm 2 > 1 6.259 2.491 9.79 0.125 2 6.385 2.489 10.79 0.206 3 6.075 2.490 9.88 0.295 4 6.276 2.488 11.86 0.397 5 5.139 2.499 8.31 0.471 6 5.633 2.487 9.88 0.686 7 6.385 2.489 9.30 1.150

[0074] The experimental conditions for nuclear magnetic resonance (NMR) experiments were as follows: temperature range of 30℃ to 35℃, humidity range of 35% to 45%, with an optimal temperature of 32℃ and humidity of 40% RH. NMR experiments were conducted on core samples under saturated formation water conditions and different displacement pressure differentials.

[0075] Furthermore, the specific steps for conducting nuclear magnetic resonance experiments on cores with different gas permeability after displacement under different displacement pressure differentials include:

[0076] Set a displacement pressure differential for the core displacement device;

[0077] Nitrogen gas is introduced into the inlet of the core displacement device to displace the formation water in the core until the water stops flowing out of the outlet of the core displacement device. The second nuclear magnetic resonance T2 spectrum of the core is obtained under the displacement pressure difference.

[0078] Increase the displacement pressure differential or replace the core with one of different gas permeability, and repeat the above operations.

[0079] Specifically, during displacement, a core displacement device is required. For NMR experiments under different displacement pressure differentials, nitrogen gas is used at constant pressure to displace formation water in the core until no more water is emitted from the outlet of the core displacement device. By continuously changing the displacement pressure differential and replacing cores with different gas permeability values, the displacement is repeated to obtain the second NMR T2 spectrum of different core samples under different displacement pressure differentials. For NMR experiments under saturated formation water conditions, only the first NMR T2 spectrum needs to be obtained by replacing cores with different gas permeability values ​​and repeating the experiment. See details... Figure 4 As shown, Figure 4 The horizontal axis represents the nuclear magnetic resonance T2 spectrum, and the vertical axis represents the percentage of water saturation under different conditions. During the experiment, the displacement pressure difference increased sequentially.

[0080] These are nuclear magnetic resonance (NMR) images of core samples under saturated formation water conditions and under different displacement pressure differentials. See details below. Figure 5 The figure shows the distribution of movable fluid saturation in the overall pores of cores with different gas permeability under different displacement pressure gradients. Figure 5 As can be seen, the saturation of movable water in the overall pores first increases with the increase of the displacement pressure gradient, and then tends to stabilize. There is an inflection point where the displacement pressure gradient decreases with the increase of gas permeability.

[0081] Furthermore, the specific steps for establishing a reservoir bound water saturation prediction model based on the first and second NMR T2 spectra include: firstly, obtaining the distribution maps of mobile fluid saturation of core samples with different gas permeability under different displacement pressure gradients based on the first and second NMR T2 spectra; secondly, obtaining the distribution maps of bound water saturation of core samples with different gas permeability under different displacement pressure gradients based on the distribution maps of mobile fluid saturation of core samples with different gas permeability under different displacement pressure gradients; and finally, establishing a reservoir bound water saturation prediction model based on the distribution maps of bound water saturation of core samples with different gas permeability under different displacement pressure gradients.

[0082] Furthermore, based on the distribution maps of mobile fluid saturation of cores with different gas permeability under different displacement pressure gradients, the specific steps for obtaining the distribution maps of bound water saturation of cores with different gas permeability under different displacement pressure gradients include: firstly, calculating the bound water saturation of cores with different gas permeability under different displacement pressure gradients based on the distribution maps of mobile fluid saturation of cores with different gas permeability under different displacement pressure gradients; then, fitting the bound water saturation of cores with corresponding gas permeability to the corresponding displacement pressure gradient to obtain multiple corresponding prediction formulas; then, calculating the bound water saturation of cores with corresponding gas permeability under different displacement pressure gradients based on the corresponding prediction formulas; finally, obtaining the distribution maps of bound water saturation of cores with different gas permeability under different displacement pressure gradients based on the calculated bound water saturation of cores with different gas permeability under different displacement pressure gradients.

[0083] Specifically, after obtaining the bound water saturation of core samples with different gas permeability under different displacement pressure gradients, the corresponding prediction formulas were obtained by fitting the relationship between the bound water saturation of core samples 1–7 and the displacement pressure gradient. (See [link to relevant documentation]). Figure 6 As shown, there is an exponential relationship between the two. The bound water saturation of different core samples under different displacement pressure gradients was calculated using the prediction formula. The set displacement pressure gradients were 0.5 MPa / cm, 1.0 MPa / cm, 1.5 MPa / cm, 2.0 MPa / cm, 2.5 MPa / cm, 3.0 MPa / cm, 3.5 MPa / cm, 4.0 MPa / cm, 4.5 MPa / cm, and 5.0 MPa / cm. The distribution map of bound water saturation under different displacement pressure gradients can be obtained by combining the bound water saturation of cores with different gas permeability obtained experimentally with the bound water saturation obtained using the prediction formula. Alternatively, the distribution map can be obtained solely using the bound water saturation of cores with different gas permeability under different displacement pressure gradients. Since the experiment is very costly, combining the prediction formula to calculate the remaining values ​​can effectively ensure accuracy while significantly reducing costs.

[0084] Specifically, preferably, based on the experimental results of bound water saturation under different displacement pressure gradients for cores with different gas permeability obtained from nuclear magnetic resonance experiments, and the bound water saturation under different displacement pressure gradients for cores with different gas permeability calculated using prediction formulas, a reservoir bound water saturation prediction model considering the influence of reservoir properties and displacement pressure gradients is established. See [link to details]. Figure 7 As shown, Figure 7 The x-axis represents the parameters influenced by the combined effects of reservoir properties and displacement pressure difference, and the y-axis represents the bound water saturation. The bound water saturation S, influenced by the combined effects of reservoir properties and displacement pressure difference, is obtained through fitting. wr The prediction formula is as follows:

[0085]

[0086] Where, k g denoted as gas permeability, ф as porosity, and dp as displacement pressure gradient.

[0087] Furthermore, the specific steps for obtaining the experimental pressure gradient of the corresponding test well section include: firstly, obtaining the initial formation pressure, bottom hole flowing pressure, single well control distance, and wellbore radius of the corresponding test well section, as well as the corresponding core length; then, using the initial formation pressure, bottom hole flowing pressure, single well control distance, wellbore radius, and core length, calculating the core holder outlet pressure of the corresponding test well section; and finally, using the core holder outlet pressure, core holder inlet pressure, and core length, calculating the experimental pressure gradient of the corresponding test well section.

[0088] Specifically, in actual construction sites, the initial formation pressure, bottom hole flowing pressure, single-well control distance, and wellbore radius of the test well section can all be measured, as can the core length and the pressure p at the outlet of the core holder. w1 The formula for calculating the experimental pressure gradient dp is as follows:

[0089]

[0090]

[0091] Where, p e p is the initial formation pressure. w For the bottom hole flowing pressure, r e For the control distance of a single well, r w Where L is the wellbore radius, and p is the core length. e1 This is the pressure at the inlet end of the core holder, which is equal to the initial formation pressure.

[0092] Furthermore, the specific steps for calculating the reservoir-generated movable water saturation of the test well section under the corresponding test pressure difference, based on the reservoir bound water saturation prediction model and experimental pressure gradient, include: first, generating a reservoir bound water saturation curve corresponding to the experimental pressure gradient based on the reservoir bound water saturation prediction model and experimental pressure gradient; then, combining the initial water saturation, gas permeability, and porosity of the corresponding test well section with the reservoir bound water saturation curve; and finally, calculating the reservoir-generated movable water saturation of the test well section under the corresponding test pressure difference.

[0093] Specifically, a reservoir bound water saturation prediction chart can be drawn based on the reservoir bound water saturation prediction model and experimental pressure gradient. However, the reservoir bound water saturation prediction chart may not perfectly match the actual test well section. See details. Figure 8 As shown, Figure 8 The horizontal axis represents the ratio of gas permeability to porosity, and the vertical axis represents the initial water saturation. Figure 8 The horizontal axis represents the ratio of gas permeability to porosity. For example, if there are four test well sections, 1-1 to 1-4, the initial water saturation and reservoir properties of these sections are plotted on a reservoir bound water saturation prediction chart. These properties include gas permeability and porosity. Therefore, coordinate points can be determined based on the initial water saturation and reservoir properties. Then, based on the specific parameters of the initial formation pressure, bottomhole flowing pressure, single-well control distance, wellbore radius, and core length of wells 1-1 to 1-4, the corresponding experimental pressure gradient is calculated. Based on the reservoir bound water saturation prediction model and the currently calculated experimental pressure gradient, a reservoir bound water saturation curve corresponding to the current experimental pressure gradient is generated. Finally, using the initial water saturation, gas permeability, and porosity of the corresponding test well section, combined with the reservoir bound water saturation curve, the reservoir's generated movable water saturation under the corresponding test pressure difference can be calculated. Among them, the initial water saturation of the gas reservoir is higher, exceeding the lower limit of water saturation of the gas reservoir, and is defined as gas and water in the same layer.

[0094] Furthermore, the condensate content of the test well section under the corresponding test conditions is calculated based on the condensate content prediction model. The specific steps include first obtaining the CO2 content in the natural gas, atmospheric pressure, and wellhead pressure of the corresponding test well section, and then calculating the condensate content of the test well section based on these parameters. Specifically, the condensate content of the test well section under the corresponding test conditions is calculated using the condensate content prediction model, thereby calculating the water content in the natural gas, and thus obtaining the condensate content of the test well section under those test conditions.

[0095] This method addresses the problem that conventional experimental evaluation methods for gas reservoir water production, commonly used in the industry, do not consider the "ultra-high pressure" characteristics of ultra-high pressure gas reservoirs. This leads to the inability to accurately predict the reservoir water production type and content of ultra-high pressure, low-permeability gas reservoirs without edge and bottom water intrusion. A new experimental method for evaluating reservoir water production in ultra-high pressure, low-permeability gas reservoirs is established, quantifying the type and content of produced water. This method guides the analysis of water production mechanisms in ultra-high pressure, low-permeability gas reservoirs and the research on rational gas reservoir production allocation during development, achieving reasonable characterization, high reliability, and high accuracy.

[0096] In the description of this application, it should be noted that the terms "upper," "lower," etc., indicating the orientation or positional relationship are based on the orientation or positional relationship shown in the accompanying drawings, and are only for the convenience of describing this application 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, and therefore should not be construed as a limitation of this application. Unless otherwise expressly specified and limited, the terms "installed," "connected," and "linked" should be interpreted broadly. For example, they can refer to a fixed connection, a detachable connection, or an integral connection; they can refer to a mechanical connection or an electrical connection; they can refer to a direct connection or an indirect connection through an intermediate medium; they can refer to the internal communication between two elements. For those skilled in the art, the specific meaning of the above terms in this application can be understood according to the specific circumstances.

[0097] It should be noted that in this application, relational terms such as "first" and "second" are used merely to distinguish one entity or operation from another, and do not necessarily require or imply any such actual relationship or order between these entities or operations. Furthermore, the terms "comprising," "including," or any other variations thereof are intended to cover non-exclusive inclusion, such that a process, method, article, or apparatus that comprises a list of elements includes not only those elements but also other elements not expressly listed, or elements inherent to such a process, method, article, or apparatus. Without further limitations, an element defined by the phrase "comprising one..." does not exclude the presence of other identical elements in the process, method, article, or apparatus that includes said element.

[0098] The above description is merely a specific embodiment of this application, enabling those skilled in the art to understand or implement this application. Various modifications to these embodiments will be readily apparent to those skilled in the art, and the general principles defined herein may be implemented in other embodiments without departing from the spirit or scope of this application. Therefore, this application is not to be limited to the embodiments shown herein, but is to be accorded the widest scope consistent with the principles and novel features claimed herein.

Claims

1. A method for evaluating water production in ultra-high pressure, low-permeability gas reservoirs, characterized in that, It comprises: establishing a condensate water content prediction model; saturating cores with different gas measured permeabilities with formation water respectively, and performing nuclear magnetic resonance experiments to obtain first nuclear magnetic resonance T2 spectra, and performing nuclear magnetic resonance experiments on cores with different gas measured permeabilities after different displacement pressure differentials to obtain second nuclear magnetic resonance T2 spectra, and establishing a reservoir irreducible water saturation prediction model according to the first and second nuclear magnetic resonance T2 spectra; obtaining an experimental pressure gradient corresponding to a test well section, calculating reservoir secondary movable water saturation of the test well section under a corresponding test pressure differential according to the reservoir irreducible water saturation prediction model and the experimental pressure gradient, and calculating condensate water content of the test well section under corresponding test conditions according to the condensate water content prediction model; The establishment of the condensate water content prediction model comprises: configuring natural gas with different CO2 contents, and mixing the natural gas with different CO2 contents with formation water respectively under different pressures; releasing a preset volume of natural gas under a corresponding pressure to obtain the mass of condensate water condensed during the release of the gas; establishing the condensate water content prediction model according to the mass of condensate water condensed when natural gas with different CO2 contents is released under different pressures; The saturation of cores with different gas measured permeabilities with formation water comprises: performing physical property tests on a plurality of cores to screen out cores with different gas measured permeabilities; washing the screened cores, drying them, and then performing vacuum treatment; saturating the treated cores with formation water respectively.

2. The method of evaluating water production from an ultra-high pressure, low permeability gas reservoir of claim 1, wherein, The nuclear magnetic resonance experiment on cores with different gas measured permeabilities after different displacement pressure differentials comprises: setting a displacement pressure differential for a core displacement device; introducing nitrogen into the inlet end of the core displacement device to displace formation water in the cores until water stops flowing out of the outlet end of the core displacement device, and obtaining the second nuclear magnetic resonance T2 spectrum of the cores under the displacement pressure differential; changing the displacement pressure differential or replacing the cores with different gas measured permeabilities, and repeating the above operations.

3. The method of evaluating water production from an ultra-high pressure, low permeability gas reservoir of claim 1, wherein, The establishment of the reservoir irreducible water saturation prediction model according to the first and second nuclear magnetic resonance T2 spectra comprises: obtaining a movable fluid saturation distribution graph of cores with different gas measured permeabilities under different displacement pressure gradients according to the first and second nuclear magnetic resonance T2 spectra; obtaining an irreducible water saturation distribution graph of cores with different gas measured permeabilities under different displacement pressure gradients according to the movable fluid saturation distribution graph of cores with different gas measured permeabilities under different displacement pressure gradients; establishing the reservoir irreducible water saturation prediction model according to the irreducible water saturation distribution graph of cores with different gas measured permeabilities under different displacement pressure gradients.

4. The method of evaluating water production from an ultra-high pressure, low permeability gas reservoir of claim 3, wherein, The establishment of the irreducible water saturation distribution graph of cores with different gas measured permeabilities under different displacement pressure gradients according to the movable fluid saturation distribution graph of cores with different gas measured permeabilities under different displacement pressure gradients comprises: According to the distribution map of the movable fluid saturation of the core with different gas-measured permeability under different displacement pressure gradients, the irreducible water saturation of the core with different gas-measured permeability under different displacement pressure gradients is calculated; The irreducible water saturation of the core corresponding to the gas-measured permeability is fitted with the corresponding displacement pressure gradient, and a plurality of corresponding prediction formulas are obtained; The irreducible water saturation of the core corresponding to the gas-measured permeability under different displacement pressure gradients is calculated according to the corresponding prediction formula; According to the calculated irreducible water saturation of the core with different gas-measured permeability under different displacement pressure gradients, the distribution map of the irreducible water saturation of the core with different gas-measured permeability under different displacement pressure gradients is obtained.

5. The method of evaluating water production from an ultra-high pressure, low permeability gas reservoir of claim 1, wherein, The experimental pressure gradient corresponding to the test well section is obtained, including: The initial formation pressure, bottom hole flowing pressure, single well control distance and wellbore radius corresponding to the test well section are obtained respectively, and the core length is obtained; The core holder outlet end pressure corresponding to the test well section is calculated by using the initial formation pressure, bottom hole flowing pressure, single well control distance, wellbore radius and core length; The experimental pressure gradient corresponding to the test well section is calculated by using the core holder outlet end pressure, core holder inlet end pressure and core length.

6. The method of evaluating water production of an ultra-high pressure low permeability gas reservoir of claim 1, wherein, The reservoir secondary movable water saturation of the test well section under the corresponding test differential pressure is calculated according to the reservoir irreducible water saturation prediction model and the experimental pressure gradient, including: The reservoir irreducible water saturation curve corresponding to the experimental pressure gradient is generated according to the reservoir irreducible water saturation prediction model and the experimental pressure gradient; The reservoir secondary movable water saturation of the test well section under the corresponding test differential pressure is calculated by using the initial water saturation, gas-measured permeability and porosity corresponding to the test well section in combination with the reservoir irreducible water saturation curve.

7. The method of evaluating water production of an ultra-high pressure low permeability gas reservoir of claim 1, wherein, The condensate water content of the test well section under the corresponding test condition is calculated according to the condensate water content prediction model, including: The CO2 content in the natural gas, atmospheric pressure and wellhead pressure corresponding to the test well section are obtained; The condensate water content of the test well section is calculated according to the CO2 content in the natural gas, atmospheric pressure and wellhead pressure.

8. The method of claim 1, wherein: the physical property test includes length, diameter, porosity, and gas-measured permeability of the core. ​

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