A quantitative prediction method for water production and sand production from natural gas hydrates

Abstract

This invention discloses a quantitative prediction method for water and sand production from natural gas hydrates, addressing the problem of the inability to quantitatively predict water and sand production in natural gas hydrate reservoirs during depressurization extraction. This invention employs multiple sets of experiments to simulate formation physical parameters, performing hydrate decomposition under different depressurization regimes and collecting water and sand production data. Finally, it establishes a cloud map of water and sand production data under different production regimes. Through this cloud map, quantitative indicators of water and sand production under a specific extraction regime can be quickly accessed, and by using certain conversion relationships, the actual water and sand production data in production wells can be obtained, thus providing reasonable guidance for the formulation of production parameters. The technical approach provided by this invention can be applied to the oil and gas field, such as sandstone and mudstone interbedded oil and gas fields, to establish quantitative prediction models and charts for water and sand production, enabling the widespread application of the invention.

Description

Technical Field

[0001] This invention relates to the field of marine natural gas hydrate resource development engineering technology, specifically to a quantitative prediction method for water production and sand production from natural gas hydrates. Background Technology

[0002] Natural gas hydrates, as a novel strategic resource, have attracted significant attention due to their vast reserves. The main approach to extracting natural gas hydrates involves disrupting their original phase equilibrium through methods such as depressurization, heating, gas replacement, and injection of inhibitors, causing them to decompose into water and methane gas, which is then extracted and recovered. During fluid extraction, sediment particles may detach and migrate due to the dragging effect, resulting in sand production. This can lead to problems such as formation depletion and wellbore instability; furthermore, solid particles carried in the fluid can cause wear and blockage of extraction equipment such as electric submersible pumps and wellbores, affecting the continuous extraction of hydrates. Natural gas hydrate reservoirs are more prone to sand production due to their shallow burial depth and poor cementation.

[0003] Sand production has become a significant factor limiting the long-term, safe, and efficient exploitation of hydrates. Currently, there is considerable research on sand production mechanisms and phenomena. It is widely accepted in the industry that hydrate exploitation is accompanied by severe sand production, and the phenomena vary across different exploitation cycles. Generally, sand production is severe but short-lived in the early stages of exploitation. In the middle stages, as pressure reduction decreases, the sand production rate gradually decreases, and the sand particle size gradually decreases, but sand production issues still arise. In the later stages of exploitation, due to changes in formation stress, there may be no sand production or severe sand production. On the other hand, existing sand production prediction and simulation software generally serves conventional oil and gas. Developed models and methods for hydrate prediction are often based on foreign hydrate reservoir water and sand production data, and after adaptive optimization, are applied to predict sand production in my country's offshore natural gas hydrates. However, the reliability of the results requires further research and verification. Overall, research on the mechanisms and phenomena of natural gas hydrate sand production is biased towards qualitative analysis, failing to provide quantitative prediction results. In actual production, qualitative judgments are often insufficient to effectively support the issuance of construction commands, requiring quantitative data analysis to optimize production parameters.

[0004] The survey found that: ① Existing research on sand production from natural gas hydrates focuses on the sand production mechanism and patterns, generally explaining it from multiple fields such as force field, thermal field, and flow field, providing relatively qualitative judgments on sand production. It neglects the important guiding significance of the absolute amount of sand produced for long-term production, and cannot meet the needs of accurate guidance for construction parameters in actual production processes. For example, patent document CN114091224A discloses a method for predicting the range and extent of sand production in marine natural gas hydrate reservoirs. This method mainly relies on the weak or uncemented characteristics of marine hydrate reservoirs. It determines the critical flow velocity for sand grain initiation through reservoir fluid erosion criteria. Based on the numerical simulation method for natural gas hydrate reservoir development, it considers the phase equilibrium of natural gas hydrate, the decomposition kinetics of natural gas hydrate, and the change in pore volume. It innovatively integrates the study of microscopic sand grain initiation with the numerical simulation study of macroscopic large-scale hydrate development, thereby determining the range and extent of sand production in large-scale natural gas hydrate reservoirs. Although it achieves quantitative analysis of the dynamic range of sand production and the change in reservoir sand concentration, this patent only performs quantitative analysis of the sand production range and cannot achieve real-time prediction of relevant parameters such as the quality and volume of sand produced. It still belongs to the category of qualitative judgment of the sand production range. In actual production, its ability to support the real-time modification of construction parameters is limited. ② Sand production prediction methods and software are generally derived from conventional oil and gas software and are divided into continuous media and discontinuous media. In recent years, discrete element simulation methods (such as PFC3D) have gradually gained recognition, but the numerical simulation results lack verification from experimental results and field test production results.

[0005] In the depressurization extraction of natural gas hydrates, if the water and sand production of the natural gas hydrate reservoir cannot be quantitatively predicted, it is impossible to effectively guide the adjustment of control parameters for well pumps, surface nozzles, etc. If production parameters do not match the formation's evolution characteristics, it can lead to anything from minor blockage of the formation-wellbore production channel and reduced gas production, to more serious issues such as formation subsidence, wellbore tool damage, or even production shutdown. Summary of the Invention

[0006] In order to solve at least one of the technical problems existing in the above-mentioned background technology, the present invention provides a quantitative prediction method for water production and sand production from natural gas hydrates.

[0007] To achieve the above objectives, the technical solution of the present invention is as follows:

[0008] A method for quantitatively predicting water production and sand production from natural gas hydrates, the method comprising:

[0009] Step 1: Construct an experimental system for quantitative prediction of sand production from natural gas hydrates. The system includes a vessel body, in which a simulated coarse sand-blocking medium is installed. The gap between the simulated coarse sand-blocking medium and the inner wall of the vessel body is used as a sand-filling zone. Experimental material inlets are spaced apart on the outer wall of the vessel body. An end cap is installed at the top of the vessel body, and a gas-liquid sand outlet is installed at the bottom of the vessel body. An outlet back pressure valve is connected to the gas-liquid sand outlet.

[0010] Step 2: Obtain in-situ / composite sand samples from the natural gas hydrate reservoir, as well as the natural gas hydrate reservoir liquid;

[0011] Step 3: The obtained in-situ / composite sand samples and liquid from the natural gas hydrate reservoir are respectively fed into the experimental material inlet to test the sand-water-gas filling rate in order to synthesize natural gas hydrate;

[0012] Step 4: After synthesizing natural gas hydrate, depressurize according to different depressurization paths. During the depressurization process, as the hydrate decomposes continuously, gas, liquid and sand three-phase substances will be produced at the gas-liquid-sand outlet. Collect and measure the liquid and sand in the gas, and obtain the corresponding time period and the cumulative water production and sand output.

[0013] Step 5: With the pressure reduction completed, the sand-filled area stops producing gas, liquid, and sand, thus ending the experiment;

[0014] Step 6: Set different reservoir parameters and different depressurization schemes, repeat steps 2-5 above, obtain multiple sets of water production and sand production data under different hydrate reservoirs and different depressurization schemes, analyze the data, and form a quantitative prediction chart and sand production prediction model for natural gas hydrate water production and sand production.

[0015] Step 7: During the trial production and exploitation of natural gas hydrates, based on different reservoir pressure stages, combined with the quantitative prediction charts and prediction models for water and sand production of natural gas hydrates, and after conversion, the predicted data for water and sand production in actual production are obtained.

[0016] Furthermore, in step 7, the conversion method is as follows:

[0017] A coarse sand-blocking medium with radius α and height β is used as the simulated casing, and the thickness of the annular sand-filled zone is γ. Actual production is done in a vertical well, using a casing with radius α and length δ. The furthest extent of the formation affected by the pressure drop decomposition, as monitored by the instruments, is approximately ε from the wellbore axis. Based on volume ratio, the water production rate obtained in the experiment is A1, and the sand production rate is B1. The water production and sand production rates per unit length of the actual production well are A2 and B2, respectively. The conversion relationship is as follows:

[0018]

[0019] Furthermore, in step 2, the experimental sand-water-aeration volume is calculated at the experimental material inlet according to the formation porosity, water saturation and hydrate saturation. Axial and circumferential pressures are applied using the end cap and vessel pressure to achieve stress conditions in the sample filling area similar to those in the reservoir.

[0020] Furthermore, the synthetic natural gas hydrate comprises:

[0021] To synthesize methane hydrate using a gas saturation method, the pressure of methane gas in the pores is increased to the target pressure value. Excess gas is introduced into the reactor and the temperature is lowered. When the temperature drops to the left of the hydrate phase equilibrium line, methane hydrate is formed.

[0022] Furthermore, the entire process of methane hydrate formation takes more than 10 hours.

[0023] Furthermore, after the methane hydrate formation process is completed, the liquid continues to be displaced into the sand-filling zone. During the displacement process, the internal pressure of the reactor is kept stable, and the remaining gas is slowly displaced by the reservoir liquid until the gas is vented.

[0024] Furthermore, in step 4, the different pressure reduction paths include two methods: uniformly reducing a fixed pressure value per unit time and non-uniformly reducing a fixed pressure value per unit time.

[0025] Furthermore, in step 2, the reservoir fluid can be seawater above the reservoir, and the in-situ reservoir sand can be replaced by seabed surface mud.

[0026] Furthermore, the calculation of sand filling, water addition, and aeration volumes based on formation porosity, water saturation, and hydrate saturation, respectively, and the application of axial and circumferential pressure using the end cap and vessel pressure to achieve stress conditions in the sample filling zone similar to those in the reservoir, includes:

[0027] During the filling process, the amount of sand to be filled into the vessel is calculated according to the reservoir's physical properties and the volume of the filling zone of the vessel. The amount of liquid mixed into the sand sample is calculated based on the hydrate saturation. An axial load is applied using the vessel end cap. Under the constraint of the vessel side wall, the axial load is partially converted into a circumferential stress load, thereby achieving a stress condition in the filling zone similar to that of the reservoir.

[0028] Furthermore, in step 6, the water production is also incorporated into the quantitative prediction chart and prediction model for natural gas hydrate sand production, so as to form the quantitative prediction chart and prediction model for natural gas hydrate water production and sand production.

[0029] Compared with the prior art, the advantages of this invention are as follows:

[0030] 1. Based on the characteristics of different hydrate reservoirs, it can establish quantitative indicators of reservoir water and sand production under different depressurization production regimes within a coarse sand control system, and generate quantitative cloud maps of water and sand production. It can also quickly provide precise construction parameters for each production stage, such as pump speed and wellhead nozzle size, by combining the hydrate distribution of the formation and the wellbore structure, and rationally arrange unblocking and formation fluid replenishment operations for different well sections.

[0031] 2. In the oil and gas sector, the technical solution provided by this invention can establish a quantitative prediction model for water and sand production in sandy and interbedded mud-sand oil and gas layers, providing precise guidance for sand control strategies and construction in oil and gas fields. The technical approach provided by this invention can be applied to the oil and gas sector, such as oil and gas fields with sandy and interbedded mud-sand layers, to establish quantitative prediction models and charts for water and sand production, thus promoting the widespread application of the invention. Attached Figure Description

[0032] Figure 1 A flowchart of a method for quantitatively predicting water production and sand production from natural gas hydrates provided in an embodiment of the present invention;

[0033] Figure 2 A schematic diagram of the experimental system for quantitative prediction of water production and sand production from natural gas hydrates provided in an embodiment of the present invention;

[0034] Figure 3 A schematic diagram of a quantitative prediction chart for sand production from type X natural gas hydrates in area X of the South China Sea.

[0035] Figure 4 A schematic diagram of a quantitative prediction chart for water and sand production from type X natural gas hydrates in area X of the South China Sea.

[0036] In the diagram: 1. End cap; 2. Experimental material inlet; 3. Reactor body; 4. Gas-liquid-sand outlet; 5. Outlet back pressure valve; 6. Simulated coarse sand-blocking medium; 7. Sand-filling area. Detailed Implementation

[0037] Example:

[0038] The technical solution of the present invention will be further described below with reference to the accompanying drawings and embodiments.

[0039] In the depressurization extraction of natural gas hydrates, if the water and sand production of the natural gas hydrate reservoir cannot be quantitatively predicted, it is impossible to effectively guide the adjustment of control parameters for well pumps, surface nozzles, etc. Once the production parameters do not match the formation evolution characteristics, it can lead to blockage of the formation-wellbore production channel and reduced gas production. In severe cases, it can cause formation subsidence, wellbore tool damage, or even production shutdown. To solve these problems, and considering the specific needs of hydrate extraction, this invention innovatively proposes a quantitative prediction method for water and sand production from natural gas hydrates.

[0040] See Figure 1 As shown in the figure, the quantitative prediction method for water production and sand production from natural gas hydrates provided in this embodiment specifically includes the following steps:

[0041] Step 1: Construct an experimental system for quantitative prediction of water production and sand production from natural gas hydrates, such as... Figure 2 As shown, the system includes a vessel body 3, inside which a simulated coarse sand-blocking medium 6 is provided. The gap between the simulated coarse sand-blocking medium 6 and the inner wall of the vessel body 3 is used as a sand-filling zone 7. Experimental material inlets 2 are provided at intervals on the outer wall of the vessel body 3. An end cap 1 is provided at the top of the vessel body, and a gas-liquid sand outlet 4 is provided at the bottom of the vessel body. An outlet back pressure valve 5 is connected to the gas-liquid sand outlet 4.

[0042] In this step, relying on the quantitative prediction experimental system for water production and sand production of natural gas hydrates, the physical property parameters and mechanical conditions of the natural gas hydrate reservoir to be studied are clarified, providing a basis for the subsequent establishment of reservoir properties at the experimental scale.

[0043] Step 2: Obtain in-situ / composite sand samples from the natural gas hydrate reservoir, as well as the natural gas hydrate reservoir liquid;

[0044] Specifically, the reservoir fluid can be seawater above the reservoir, and the in-situ reservoir sand can be replaced by seabed surface mud, ensuring the reliability of the experimental conclusions while reducing experimental costs. Simultaneously, the connections and seals of all system components and sensors are checked for proper functioning. The data transmission and storage status are tested to lay the foundation for the successful conduct of the experiment.

[0045] Step 3: The obtained in-situ / composite sand samples and liquid from the natural gas hydrate reservoir are respectively introduced into the experimental material inlet to conduct experimental sand-water-gas filling to synthesize natural gas hydrate.

[0046] Specifically, this includes calculating the amounts of sand filling, water addition, and aeration based on formation porosity, water saturation, and hydrate saturation, and applying axial and circumferential pressure using the end cap and vessel body pressure. For example, during the filling process, the amount of sand to be filled into the vessel body is calculated based on the reservoir's physical properties and the volume of the sand-filling zone 7 within the vessel body. The amount of liquid mixed into the sand sample is also calculated based on the hydrate saturation. An axial load is applied using the vessel end cap 1. Under the constraint of the vessel body sidewall 3, the axial load is partially converted into a circumferential stress load, thus achieving stress conditions in the sand-filling zone 7 similar to those in the reservoir.

[0047] The hydrate synthesis process includes: synthesizing hydrates via gas saturation, increasing the pore methane gas pressure to 10 MPa to facilitate hydrate synthesis, introducing excess gas into the reactor and initiating cooling. Once the temperature drops to the left of the hydrate phase equilibrium line, methane hydrates are formed. This process is carried out slowly, generally recommended to exceed 10 hours. The purposes are twofold: firstly, to ensure sufficient hydrate synthesis within the pores of the sand-filled zone; and secondly, to provide sufficient time for the transition between axial pressure and axial stress, thereby mitigating the anisotropy of the artificial reservoir's physical properties, allowing for sufficient stress-strain transition, and improving the similarity between the simulated and real reservoirs. After this process, liquid is continuously displaced from the sand-filled zone. During the displacement process, the pressure-stability system inside the reactor remains stable to prevent hydrate decomposition. The remaining gas is slowly displaced using reservoir liquid until the gas is completely exhausted. The final conditions inside the reactor are reservoir mud-sand-hydrate-pore water-stress.

[0048] Step 4: After synthesizing natural gas hydrate, depressurization is carried out according to different depressurization paths. During the depressurization process, as the hydrate decomposes continuously, gas, liquid and sand three-phase substances will be produced at the gas-liquid-sand outlet. The liquid and sand are collected and measured to obtain the corresponding time period and the cumulative water production and sand output.

[0049] Specifically, this includes: an outlet back pressure valve 5 is installed at the outlet of the vessel, enabling precise control of the internal pressure of the vessel. The outlet back pressure valve 5 is controlled to reduce pressure according to the experimentally set path. The pressure reduction path can be set to two main methods: ① uniformly reducing a fixed pressure value per unit time; ② non-uniformly reducing a fixed pressure value per unit time. During the pressure reduction process, as the hydrate continuously decomposes, a three-phase substance of gas, liquid, and sand will be produced at the gas-liquid-sand outlet. The liquid and sand are collected and measured to obtain the corresponding time period and the cumulative water and sand production. This provides data support for the subsequent establishment of a quantitative model for water and sand production.

[0050] Step 5: As the pressure reduction ends, the sand-filled area stops producing gas, liquid, and sand, thus ending the experiment.

[0051] Step 6: Set different reservoir parameters and different depressurization schemes, and repeat steps 2-5 above to obtain multiple sets of water production and sand production data under different hydrate reservoirs and different depressurization schemes. Utilize this data analysis system, specifically: first, create multiple tables to summarize the data; refer to Tables 1 and 2 for examples.

[0052] Table 1. Production water and sand output data under a pressure drop rate of 1 MPa / d.

[0053] Pressure drop (MPa) Water production (g) Sand output (g) 10.0→9.0 9.0→8.0 … Cumulative amount

[0054] Table 2. Production water and sand output data at a pressure drop rate of 0.5 MPa / d.

[0055] Pressure drop (MPa) Water production (g) Sand output (g) 10→9.5 9.5→9.0 … Cumulative amount

[0056] Repeated quantitative experiments on permeate and sand production under different depressurization rates yielded several data sets similar to those in Tables 1 and 2. Generally, different depressurization rates produce different permeate and sand production phenomena and cumulative production amounts. The absolute values ​​of the cumulative permeate and sand production amounts under different depressurization rates were entered into the data processing software ORIGIN, and data cloud plots were generated using the software. Based on the obtained relationship between depressurization rate, permeate, and sand production data sets, a curve fitting method was used, where permeate volume W, sand production volume S, and depressurization rate V. The values ​​of W and S were then calculated from V using the fitting equation, establishing a quantitative prediction model, as shown in the formula:

[0057] W = f(V, H)

[0058] S=f(V,H)

[0059] H represents other influencing factors in the hydrate development process, such as heating during depressurization, liquid injection to increase production, and unblocking. By incorporating appropriate experimental methods into the depressurization experiment, a more complete and systematic prediction chart and model for natural gas hydrate water production and sand production can be established.

[0060] Using the above methods, a quantitative prediction chart and prediction model for sand production from type X natural gas hydrates in area X of the South China Sea can be generated. (See attached image.) Figure 3 Water production can also be incorporated into the model to create a three-dimensional quantitative prediction map and prediction model for water and sand production from X-type natural gas hydrates in the X-area of ​​the South China Sea. (See attached image.) Figure 4 .

[0061] Step 7: During the trial production and exploitation of natural gas hydrates, based on different reservoir pressure stages, and combined with the quantitative prediction chart and sand production prediction model of natural gas hydrate water and sand production, the corresponding water and sand production amounts are quickly obtained. These are then converted using conversion formulas to obtain actual water and sand production data. This provides strong support for adjusting construction parameters during exploitation, such as wellhead nozzles and ESP frequency, as well as determining the unblocking cycle of the sand-controlling medium in the hydrate reservoir. The actual water and sand production prediction data is then obtained through conversion.

[0062] Specifically, the conversion formula is as follows:

[0063] During the experiment, it was assumed that the formation response was uniform during reservoir depressurization, thus the formation water and sand production per unit volume would be the same. A coarse sand-blocking medium with radius α and height β was used as the simulated casing, and the thickness of the annular sand-filling zone was γ. Actual production was conducted in a vertical well, using a casing with radius α and length δ. The furthest extent of the formation affected by the depressurization decomposition, as monitored by the instruments, was approximately ε from the wellbore axis. Based on volume ratios, the water production obtained in the experiment was A1, and the sand production was B1. The water and sand production per unit length (1m well section) of the actual production well were A2 and B2, respectively. The conversion formula is as follows:

[0064]

[0065] Through the innovative design of the above-mentioned method steps, the quantitative prediction system and method for natural gas hydrate water production and sand production provided by this invention has two major technical advantages, specifically including:

[0066] 1. Based on the characteristics of different hydrate reservoirs, it can establish quantitative indicators of reservoir water and sand production under different depressurization production regimes within a coarse sand control system, and generate quantitative cloud maps of water and sand production. It can also quickly provide precise construction parameters for each production stage, such as pump speed and wellhead nozzle size, by combining the hydrate distribution of the formation and the wellbore structure, and rationally arrange unblocking and formation fluid replenishment operations for different well sections.

[0067] 2. In the oil and gas sector, the technical solution provided by this invention can establish a quantitative prediction model for water and sand production in sandy and interbedded mud-sand oil and gas layers, providing precise guidance for sand control strategies and construction in oil and gas fields. The technical approach provided by this invention can be applied to the oil and gas sector, such as oil and gas fields with sandy and interbedded mud-sand layers, to establish quantitative prediction models and charts for water and sand production, thus promoting the widespread application of the invention.

[0068] The above embodiments are merely illustrative of the technical concept and features of the present invention, and are intended to enable those skilled in the art to understand the content of the present invention and implement it accordingly. They should not be construed as limiting the scope of protection of the present invention. All equivalent changes or modifications made based on the essence of the content of the present invention should be covered within the scope of protection of the present invention.

Claims

1. A method for quantitatively predicting water production and sand production from natural gas hydrates, characterized in that, The method includes: Step 1: Construct an experimental system for quantitative prediction of sand production from natural gas hydrates. The system includes a vessel body, in which a simulated coarse sand-blocking medium is installed. The gap between the simulated coarse sand-blocking medium and the inner wall of the vessel body is used as a sand-filling zone. Experimental material inlets are spaced apart on the outer wall of the vessel body. An end cap is installed at the top of the vessel body, and a gas-liquid sand outlet is installed at the bottom of the vessel body. An outlet back pressure valve is connected to the gas-liquid sand outlet. Step 2: Obtain in-situ / composite sand samples from the natural gas hydrate reservoir, as well as the natural gas hydrate reservoir liquid; Step 3: The obtained in-situ / composite sand samples and liquid from the natural gas hydrate reservoir are respectively fed into the experimental material inlet to test the sand-water-gas filling rate in order to synthesize natural gas hydrate; Step 4: After synthesizing natural gas hydrate, depressurize according to different depressurization paths. During the depressurization process, as the hydrate decomposes continuously, gas, liquid and sand three-phase substances will be produced at the gas-liquid-sand outlet. Collect and measure the liquid and sand in the gas, and obtain the corresponding time period and the cumulative water production and sand output. Step 5: With the pressure reduction completed, the sand-filled area stops producing gas, liquid, and sand, thus ending the experiment; Step 6: Set different reservoir parameters and different depressurization schemes, repeat steps 2-5 above, obtain multiple sets of water production and sand production data under different hydrate reservoirs and different depressurization schemes, analyze the data, and form a quantitative prediction chart and sand production prediction model for natural gas hydrate water production and sand production. Step 7: During the trial production and exploitation of natural gas hydrates, based on different reservoir pressure stages, combined with the quantitative prediction charts and prediction models for water and sand production of natural gas hydrates, and after conversion, the predicted data for water and sand production in actual production are obtained. In step 7, the conversion method is as follows: A coarse sand-blocking medium with radius α and height β is used as the simulated casing, and the thickness of the annular sand-filled zone is γ. Actual production is done in a vertical well, using a casing with radius α and length δ. The furthest extent of the formation affected by the pressure drop decomposition, as monitored by the instruments, is approximately ε from the wellbore axis. Based on volume ratio, the water production rate obtained in the experiment is A1, and the sand production rate is B1. The water production and sand production rates per unit length of the actual production well are A2 and B2, respectively. The conversion relationship is as follows: 。 2. The quantitative prediction method for water production and sand production from natural gas hydrates as described in claim 1, characterized in that, In step 2, the experimental sand-water-air filling and aeration processes at the experimental material inlet include: The amount of sand filling, water addition, and aeration is calculated based on the formation porosity, water saturation, and hydrate saturation, respectively. Axial and circumferential pressures are applied using the end cap and vessel pressure to achieve stress conditions in the sample filling area similar to those in the reservoir.

3. The quantitative prediction method for water production and sand production from natural gas hydrates as described in claim 1, characterized in that, The synthetic natural gas hydrate includes: To synthesize methane hydrate using a gas saturation method, the pressure of methane gas in the pores is increased to the target value. Excess gas is introduced into the reactor and the temperature is lowered. When the temperature drops to the left of the hydrate phase equilibrium line, methane hydrate is formed.

4. The quantitative prediction method for water production and sand production from natural gas hydrates as described in claim 3, characterized in that, The entire process of methane hydrate formation takes more than 10 hours.

5. The quantitative prediction method for water production and sand production from natural gas hydrates as described in claim 3 or 4, characterized in that, After the methane hydrate formation process is completed, the liquid continues to be displaced into the sand-filling zone. During the displacement process, the internal pressure of the reactor is kept stable, and the remaining gas is slowly displaced by the reservoir liquid until the gas is vented.

6. The quantitative prediction method for water production and sand production from natural gas hydrates as described in claim 1, characterized in that, In step 4, the different pressure reduction paths include two methods: uniformly reducing a fixed pressure value per unit time and non-uniformly reducing a fixed pressure value per unit time.

7. The method for quantitative prediction of water production and sand production from natural gas hydrates as described in claim 1, characterized in that, In step 2, the reservoir fluid is seawater above the reservoir, and the in-situ reservoir sand is replaced by seabed surface mud.

8. The method for quantitative prediction of water production and sand production from natural gas hydrates as described in claim 2, characterized in that, The process involves calculating the sand filling, water addition, and aeration volumes based on formation porosity, water saturation, and hydrate saturation, respectively. Axial and circumferential pressures are applied using the end cap and vessel body pressure to achieve stress conditions in the sample-filled area similar to those in the reservoir. This includes: During the filling process, the amount of sand to be filled into the vessel is calculated according to the reservoir's physical properties and the volume of the filling zone of the vessel. The amount of liquid mixed into the sand sample is calculated based on the hydrate saturation. An axial load is applied using the vessel end cap. Under the constraint of the vessel side wall, the axial load is partially converted into a circumferential stress load, thereby achieving a stress condition in the filling zone similar to that of the reservoir.

9. The quantitative prediction method for water production and sand production from natural gas hydrates as described in claim 1, characterized in that, In step 6, the water production is also incorporated into the quantitative prediction chart and prediction model for natural gas hydrate sand production, in order to form the quantitative prediction chart and prediction model for natural gas hydrate water production and sand production.

Images