A highly efficient combined extraction system and method for deep-water shallow gas and natural gas hydrates

Abstract

This invention relates to a highly efficient co-production system and method for deep-water shallow gas and natural gas hydrates, belonging to the field of deep-water oil and gas and natural gas hydrate development. It employs a one-injection-four-production well network, deploying one central well and four surrounding production wells in the target reservoir area. The central well is initially used for fracturing and fracture creation and participates in production; later, based on production decline or reservoir temperature reduction, it is converted from production to injection, used to inject anhydrous self-generating heat materials into the artificial fracture network. The four surrounding production wells are respectively deployed in the natural gas hydrate reservoir and the shallow gas reservoir, used for depressurization production in the target reservoir, achieving the co-production of shallow gas and hydrate decomposition gas. This invention solves problems existing in the development of deep-water shallow gas and natural gas hydrates, such as low reservoir permeability, difficult gas migration, significant reservoir temperature drop in the later stages of simple depressurization production, rapid gas production decline, easy secondary formation of natural gas hydrates, and difficulty in the co-production and efficient extraction of shallow gas and hydrates.

Description

Technical Field

[0001] This invention relates to a highly efficient co-production system and method for deep-water shallow gas and natural gas hydrates, and more particularly to a system and method that employs a one-injection-four-production well network, through fracturing and creating fractures in the central well, initial gas production, subsequent production and injection with the injection of anhydrous self-generating heat material for in-situ heat replenishment, combined with stratified depressurization production from four surrounding production wells, to achieve the co-production of deep-water shallow gas and natural gas hydrates, belonging to the field of deep-water oil and gas and natural gas hydrate development technology. Background Technology

[0002] Natural gas hydrates are cage-like crystalline substances formed by natural gas and water under low temperature and high pressure conditions. They are widely distributed in deep-water sediments and terrestrial permafrost areas, characterized by large resource reserves, high energy density, and clean, low-carbon properties. Shallow-deep gas is free natural gas found in shallow strata within deep water. In some deep-water areas, shallow gas and natural gas hydrates often exhibit symbiotic, associated, or adjacent distribution relationships, and both have high development and utilization value.

[0003] Currently, the main methods for extracting natural gas hydrates include depressurization, thermal injection, inhibitor injection, carbon dioxide replacement, and solid-state fluidization. Among these, depressurization involves reducing the bottom hole pressure of the production well, causing the natural gas hydrate's environment to deviate from its phase equilibrium conditions, thus promoting the decomposition of the hydrate into natural gas and water, which are then extracted. Depressurization has advantages such as relatively simple process, low energy consumption, and rapid gas production response, and is considered one of the more promising methods for extracting natural gas hydrates.

[0004] However, during the depressurization extraction of natural gas hydrates, the decomposition of hydrates requires the absorption of a large amount of heat, which can easily lead to a decrease in reservoir temperature. When the reservoir temperature continues to drop, further decomposition of hydrates is inhibited, the gas production rate decreases, and the sustainability of gas production deteriorates. In addition, deep-water natural gas hydrate reservoirs are usually characterized by shallow burial, poor cementation, non-diagenetic or weakly diagenetic formation, and low permeability. The reservoir's seepage capacity is poor, and shallow gas and hydrate decomposition gas cannot be efficiently transported to production wells, thus limiting the development efficiency of deep-water shallow gas and natural gas hydrates.

[0005] Conventional heat injection methods can supplement the heat for the decomposition of natural gas hydrates to some extent. However, hot water, steam, or other external heat sources are prone to heat loss during transport and diffusion in deep-water formations, resulting in problems such as high energy consumption, limited heating range, and insufficient heating efficiency. Especially in the low-temperature environment of deep water, it is difficult for external heat to be efficiently transferred to the deep part of the hydrate reservoir, making it difficult to meet the heat required for continuous decomposition.

[0006] Anhydrous self-generating heat materials can undergo exothermic reactions in aqueous environments, thereby achieving in-situ heating within the reservoir. Compared to conventional external heating methods, anhydrous self-generating heat materials offer advantages such as heat release location closer to the target reservoir, lower heat loss, and faster heating response. However, deep-water natural gas hydrate reservoirs typically have low permeability. Without establishing effective reservoir channels beforehand, anhydrous self-generating heat materials struggle to penetrate deep into the reservoir, tending to accumulate near the wellbore, resulting in a limited heating range and hindering their full in-situ heating potential. Furthermore, if the anhydrous self-generating heat materials come into premature contact with water during transport, premature heat release, agglomeration, or localized deposition may occur, affecting the material's transport to deeper reservoirs and subsequent in-situ heating effects.

[0007] Furthermore, deep-water environments are characterized by low temperatures and high pressures. During the migration and production of natural gas generated from hydrate decomposition into production wells, natural gas hydrates may re-form, causing blockages in reservoir pore throats, artificial fractures, wellbores, or gathering and transportation channels, affecting the continuity and safety of production. Currently, there is a lack of systems and methods for simultaneously achieving fracturing and permeability enhancement, efficient initial pressure reduction and gas production, on-demand in-situ heating in the later stages, and stratified synergistic production of shallow gas and hydrate decomposition gas, specifically for deep-water shallow gas and natural gas hydrate coexisting or adjacent reservoirs.

[0008] Therefore, there is an urgent need to provide a system and method suitable for the co-production and development of deep-water shallow gas and natural gas hydrates, in order to solve the problems in existing technologies such as insufficient flow channels in low-permeability hydrate reservoirs, significant production decline in the later stages of simple depressurization extraction, inhibition of continuous hydrate decomposition by reservoir cooling, large heat loss from conventional heating, difficulty in the entry of anhydrous self-generating heat materials into deep reservoirs, and the easy occurrence of secondary hydrate formation and blockage in deep-water low-temperature and high-pressure environments. Summary of the Invention

[0009] To address the shortcomings of existing technologies, this invention proposes a highly efficient combined production system and method for deep-water shallow gas and natural gas hydrates. This system aims to solve problems encountered during the development of deep-water shallow gas and natural gas hydrates, such as low reservoir permeability, difficulty in gas migration, significant reservoir temperature drop in the later stages of simple depressurization extraction, rapid decline in gas production, large heat loss from conventional heating, difficulty in penetrating deep reservoirs with anhydrous self-generating heat materials, easy secondary formation of natural gas hydrates, and difficulty in the coordinated and efficient extraction of shallow gas and hydrates.

[0010] This invention employs a one-injection-four-production well network, deploying one central well and four surrounding production wells in the target reservoir area. The central well is initially used for fracturing and fracture creation, participating in production. Later, depending on production decline or reservoir temperature reduction, it is converted from production to injection, used to inject anhydrous self-generating heat materials into the artificial fracture network. The four surrounding production wells are respectively located in the natural gas hydrate reservoir and the shallow gas reservoir, used for depressurization production in the target reservoir, achieving coordinated production of shallow gas and hydrate decomposition gas.

[0011] Another objective of this invention is to provide a development method in which the central well is first fractured and participates in the initial production, and then converted to injection based on the decline in production or the decrease in reservoir temperature in the later stage. This allows the central well to play the roles of fracturing and permeability enhancement, depressurization and gas production, and in-situ heat replenishment at different development stages, thereby improving the utilization efficiency of the well network.

[0012] Another objective of this invention is to provide a layered well network layout with one injection and four production wells, in which two production wells arranged opposite each other are located in a natural gas hydrate reservoir, and the other two production wells arranged opposite each other are located in a shallow gas reservoir, thereby forming relatively balanced pressure reduction and diffusion zones in different reservoirs, and realizing the coordinated development of rapid shallow gas production and continuous gas supply from the decomposition of natural gas hydrates.

[0013] Another objective of this invention is to inject anhydrous self-generating heat material into the artificial fracture network in the later stage to provide in-situ heating in the deep reservoir, thereby mitigating the reservoir cooling caused by hydrate decomposition, reducing the risk of secondary hydrate formation in reservoir pore throats, artificial fractures, wellbores, or gathering and transportation channels under deep-water low-temperature and high-pressure environments, and improving the continuity and safety of the synergistic production process.

[0014] The present invention adopts the following technical solution:

[0015] A high-efficiency combined production system for deep-water shallow gas and natural gas hydrate includes an offshore platform, an injection pipeline, a wellhead device, a central well, production wells arranged around the central well, and an artificial fracture network extending from the central well to the target reservoir. The central well passes through the seawater layer and the seabed mud surface and extends to the target reservoir area, which includes natural gas hydrate reservoirs and shallow gas reservoirs.

[0016] One end of the central well and the production well are connected to the artificial fracture network, the other end of the central well is connected to the offshore platform through a wellhead device and an injection pipeline, and the other end of the production well is connected to the offshore platform through a production fluid pipeline.

[0017] The number of production wells is four, forming a four-injection well network with the central well. The central well is located at the center of the four-injection well network, and the four production wells are distributed around the central well. Two of the wells are arranged opposite each other and located in the same reservoir, while the other two wells are also arranged opposite each other and located in another reservoir.

[0018] An in-situ heat release zone is formed within the artificial fracture network by injecting anhydrous self-generating heat material.

[0019] Preferably, the central well is used in the early stage of development to inject fracturing fluid into the target reservoir area to form an artificial fracture network; after fracturing is completed, the central well and the four production wells jointly participate in the initial depressurization production; after a period of production operation, the central well is converted from the production state to the injection state.

[0020] Preferably, the central well and the production well are vertical wells, directional wells, or horizontal wells.

[0021] Preferably, the anhydrous self-generating heat material is a capsule-type anhydrous self-generating heat material, comprising a core material and a coating layer. The core material is a water-reactive anhydrous material, and the coating layer is used to isolate or delay the entry of water into the core material during the wellbore transport stage, reducing the risk of premature heat release from the core material. The anhydrous self-generating heat material enters the deep reservoir along artificial fractures and the pores around the fractures. When the anhydrous self-generating heat material is a capsule-type anhydrous self-generating heat material, the coating layer gradually opens under the action of reservoir water infiltration, water swelling, fracture wall compression, or pore throat shearing, allowing the core material to react exothermically with reservoir water, residual fracturing fluid, or decomposition water of natural gas hydrates. This releases heat in situ within the reservoir, replenishing the heat required for hydrate decomposition, promoting further hydrate decomposition, and reducing the risk of secondary hydrate formation during gas migration.

[0022] The core material is one or more of calcium oxide, magnesium oxide, calcium-based composite exothermic material, magnesium-based composite exothermic material, and aluminum-based composite exothermic material; the core material is preferably a calcium oxide-based anhydrous exothermic material.

[0023] Preferably, the particle size of the anhydrous self-generating heat material meets the following requirements. ,in This represents the particle size, in mm, corresponding to a cumulative throughput of 90% in the particle size distribution of the anhydrous self-generating heat material. This indicates the minimum effective aperture of the artificial crack, in mm. This indicates the bridge blockage prevention factor, ranging from 3 to 5.

[0024] Preferably, the artificial fracture network is formed by fracturing in the central well, including artificial main fractures and secondary fractures. The artificial main fractures extend from the central well 1 to the four production wells. The secondary fracture network 10 can be formed by increasing the net fracturing pressure, using sand-carrying fracturing fluid to support the fractures, temporarily plugging and redirecting fracturing, repeating fracturing, or re-opening the natural weak surface of the reservoir.

[0025] Preferably, the syndicated production system also includes a monitoring and control unit for monitoring the target reservoir temperature, bottom hole pressure of the central well and four production wells, gas production, water production, wellbore pressure, wellbore temperature, and the risk of secondary hydrate formation.

[0026] The monitoring and control unit includes a downhole pressure sensor, a downhole temperature sensor, a distributed fiber optic temperature sensor, a wellhead pressure sensor, a wellhead temperature sensor, a gas flow meter, a liquid flow meter, a sand-bearing monitoring device, and a data acquisition and control module.

[0027] The downhole pressure and temperature sensors are respectively arranged in the target formations of the central well and the four production wells to obtain bottom hole pressure and temperature. The distributed fiber optic temperature sensors are deployed along the wellbore of the central well and the production wells to obtain the temperature distribution in the wellbore and near-wellbore area. The wellhead pressure and temperature sensors are installed at the wellhead device to obtain wellhead pressure and temperature. The gas flow meter and liquid flow meter are respectively installed at the gas phase outlet and liquid phase outlet to obtain gas production and water production. The sand-bearing monitoring device is installed in the produced fluid pipeline to determine the sand production risk. The data acquisition and control module is used to receive temperature, pressure, flow rate, and sand production risk monitoring data, and adjust the timing of production-to-injection conversion in the central well, the injection volume of anhydrous self-generating heat material, and the depressurization of the production wells accordingly.

[0028] A highly efficient method for the combined production and extraction of deep-water shallow gas and natural gas hydrates, implemented through the aforementioned highly efficient combined production and extraction system for deep-water shallow gas and natural gas hydrates, includes the following steps:

[0029] S1, Identify deep-water shallow gas reservoirs, natural gas hydrate reservoirs, and their spatial relationships in the target sea area to determine the target development area; the spatial relationships include coexistence, association, vertical proximity, lateral proximity, or interconnection through connecting segments between shallow gas reservoirs and natural gas hydrate reservoirs.

[0030] S2 involves deploying a central well in the target development area and four production wells around the central well to form a network of one injection and four production wells. Two of the production wells are located in the natural gas hydrate reservoir, while the other two are located in the shallow gas reservoir.

[0031] S3 involves injecting fracturing fluid into the target reservoir through the central well to create artificial fractures in shallow gas reservoirs, natural gas hydrate reservoirs, adjacent areas, coexisting areas, or connected sections of shallow gas and natural gas hydrates, forming an artificial fracture network extending from the central well to the four surrounding production wells.

[0032] S4. After fracturing is completed, the central well is not immediately injected with anhydrous self-generating heat material, but participates in the initial depressurization production as a production well. At the same time, the four surrounding production wells carry out stratified depressurization production of shallow gas reservoirs and natural gas hydrate reservoirs, so that shallow gas, hydrate decomposition gas and formation water are collected and extracted to the central well and surrounding production wells.

[0033] S5, during the initial production process, monitor the gas production, water production, bottom hole pressure, wellbore temperature, reservoir temperature, and risk of secondary hydrate formation in the central well and four production wells; when the gas production drops below the preset gas production threshold, the reservoir temperature drops below the preset temperature threshold, or the risk of secondary hydrate formation reaches the preset risk threshold, the central well is switched from production state to injection state.

[0034] S6. After the central well is converted to the injection state, anhydrous self-generating heat material is injected into the artificial fracture network and the pores around the fractures through the central well. The anhydrous self-generating heat material enters the artificial fracture network with the low water content carrying liquid.

[0035] S7, after the anhydrous self-generating heat material enters the artificial fracture network, it undergoes an exothermic reaction upon contact with reservoir water, residual fracturing fluid, or decomposition water of natural gas hydrates, releasing heat in situ inside the target reservoir.

[0036] During or after the injection of anhydrous self-generating heat material into the central well (S8), the four surrounding production wells continue to depressurize and produce gas. This allows the shallow gas to continue flowing into the shallow gas reservoir production wells under the pressure difference and be extracted. The natural gas hydrate continues to decompose under the combined action of depressurization and in-situ heating. The resulting hydrate decomposition gas is collected and extracted into the natural gas hydrate reservoir production wells. The produced shallow gas, hydrate decomposition gas, and formation water are then collected and transported after gas-liquid separation.

[0037] Preferably, in step S3, the fracturing fluid is seawater, fresh water, low-damage fracturing fluid, proppant-carrying fracturing fluid, or a combination thereof;

[0038] During fracturing, the fracturing pressure is greater than the target reservoir initiation pressure and is controlled within the formation safety pressure range;

[0039] Preferably, in step S4, the two production wells located in the shallow gas reservoir preferentially produce shallow gas, the two production wells located in the natural gas hydrate reservoir reduce the pressure of the hydrate reservoir and promote the decomposition of natural gas hydrate, and the central well assists in producing shallow gas, hydrate decomposition gas and formation water in the fracturing connected area.

[0040] Preferably, in step S5, during the initial production process, production wells located in shallow gas reservoirs adopt a relatively large depressurization range to quickly form shallow gas venting channels and increase early gas production; production wells located in natural gas hydrate reservoirs preferably adopt a step-by-step depressurization method to reduce the risk of sand production, sudden increase in water production, or formation instability in hydrate reservoirs.

[0041] No. The bottom pressure of the production well during each depressurization stage can be expressed as:

[0042]

[0043] in, For the first Bottom hole pressure of production wells during each depressurization stage, MPa; This refers to the bottom hole pressure of the production well in the previous depressurization stage, in MPa. For the first The depressurization range of each depressurization stage, in MPa; the depressurization range is determined based on reservoir stability, water production, sand production risk, and hydrate decomposition requirements.

[0044] The bottom hole pressure of the production well is determined based on the target reservoir temperature and the phase equilibrium pressure of natural gas hydrate. For natural gas hydrate in the target reservoir, its phase equilibrium pressure can be determined based on the reservoir temperature according to the following empirical relationship:

[0045]

[0046] in, For natural gas hydrates at reservoir temperature The phase equilibrium pressure at the specified point, in MPa; Reference pressure, MPa; denoted as absolute reservoir temperature in K; A and B are fitting coefficients related to natural gas composition, formation water salinity, and target reservoir conditions, where A is dimensionless and B is in K.

[0047] To promote the decomposition of natural gas hydrates, the bottom hole pressure of production wells located in natural gas hydrate reservoirs should preferably meet the following requirements:

[0048] in, The bottom pressure of the production well, in MPa; The reservoir temperature (K) within the control area of ​​the production well; For temperature The equilibrium pressure of the hydrate phase at the specified depth, MPa; The safe pressure reduction differential to promote stable decomposition of hydrates is MPa;

[0049] In step S5, the gas production threshold is determined based on the initial stable gas production. When the current gas production drops to 30%-70% of the initial stable gas production and continues for 3-7 days, the gas production threshold is considered to have been reached.

[0050] The temperature threshold is determined based on the initial reservoir temperature or the reservoir temperature during the initial stable production stage. The temperature threshold is the temperature that decreases by 2-3K compared to the initial stable production stage.

[0051] when or At that time, it was considered that the risk threshold for secondary hydrate formation had been reached, among which Represents any position in the gas transport channel Pressure at the location, Indicates temperature The equilibrium pressure of the hydrate phase below; This indicates any position in the gas transport channel. The temperature at that location Indicates pressure The equilibrium temperature of the hydrate phase, K; K represents the safe temperature margin to prevent the secondary formation of hydrates.

[0052] Preferably, in step S6, the amount of anhydrous self-generating heat material injected is determined based on the heat required for the decomposition of natural gas hydrates in the target heating area, the heat required for reservoir heating, and the heat release per unit mass of the anhydrous self-generating heat material.

[0053] The heat required for the decomposition of natural gas hydrates within the target heating area is determined by the following formula:

[0054]

[0055] in, This represents the heat absorbed during the decomposition of natural gas hydrates, in J; The amount of natural gas released from the decomposition of hydrates within the target heating area is expressed in mol. The enthalpy of decomposition of natural gas hydrate, expressed as a unit amount of substance, is J / mol.

[0056] The amount of heat required to raise the reservoir temperature is determined by the following formula:

[0057]

[0058] in, The amount of heat required to heat the reservoir, J; The reservoir skeleton density is expressed in kg / m³. 3 ; is the specific heat capacity of the reservoir framework, J / (kg·K); Let m be the reservoir skeleton volume within the target heating region. 3 ; Density of formation water, kg / m³ 3 ; is the specific heat capacity of formation water, J / (kg·K); Let m be the volume of formation water within the target heating area. 3 ; The initial reservoir temperature is given in °C. Target reservoir temperature, °C;

[0059] Therefore, the theoretical injection mass of the anhydrous self-generating heat material can be determined by the following formula:

[0060]

[0061] in, The theoretical injection mass of the anhydrous self-generating heat material, in kg; The heat release per unit mass of the anhydrous self-generating material is expressed in J / kg; when the anhydrous self-generating material is a capsule-type anhydrous self-generating material... The equivalent heat release per unit mass of capsule-type anhydrous self-generating heat material, J / kg; This is the in-situ heat utilization coefficient, which is dimensionless. The value can be determined based on reservoir heat loss, fracture development, material distribution, and reservoir heterogeneity, and can range from 0.3 to 0.8, preferably 0.4 to 0.6. The lower the reservoir heat loss, the more uniform the material distribution, and the better the fracture connectivity, the better the results. The larger the value;

[0062] Preferably, the theoretical injection quality is corrected during actual construction:

[0063]

[0064] in, The actual injected mass of the anhydrous self-generating heat material is expressed in kg. For the injection correction coefficient, dimensionless, and The value ranges from 1.2 to 1.5.

[0065] In step S6, the low-water-content carrier liquid is used to suspend, disperse, and transport the anhydrous self-generating heat material.

[0066] The anhydrous self-generating heat material is a capsule-type anhydrous self-generating heat material. The coating layer of this capsule-type anhydrous self-generating heat material gradually opens under the influence of reservoir water infiltration, water swelling, fracture wall compression, or pore throat shearing, exposing the core material and allowing it to contact and release heat with reservoir water, residual fracturing fluid, or decomposition water from natural gas hydrates. The released heat is transferred to the surrounding natural gas hydrate reservoir through the artificial fracture walls and reservoir pores, increasing the reservoir temperature, replenishing the heat required for the endothermic decomposition of natural gas hydrates, and promoting the continued decomposition of natural gas hydrates into natural gas and water.

[0067] During the wellbore transport stage, the anhydrous self-generating thermal material is isolated or has its moisture ingress into the core material by a coating layer, and gradually opens up after entering the artificial fracture network. By controlling the particle size of the anhydrous self-generating thermal material, the discharge rate of the low water-cut carrying fluid, the injection pressure, and the bottom hole pressure of the four production wells, the anhydrous self-generating thermal material is transported along the artificial main fracture and secondary fracture network toward the four production wells and distributed in the target area between the central well and the four surrounding production wells.

[0068] Preferably, in step S8, in order to make the pressure reduction sweep area of ​​the surrounding production wells overlap with the fracture network and the heat release area of ​​the anhydrous self-generating heat material formed by the central well, the well distance between the production wells and the central well can be determined according to the reservoir pressure diffusion characteristics. The pressure reduction sweep radius of the production well can be determined by the following approximate relationship:

[0069]

[0070] in, For production wells during production time The radius of the voltage drop wave, in meters; m is the reservoir permeability. 2 ; Reservoir porosity, dimensionless; The viscosity of the fluid is Pa·s; The overall compression factor is Pa⁻¹; This is a pressure wave correction factor, dimensionless;

[0071] Well spacing between production wells and center wells Preferred satisfaction:

[0072]

[0073] in, Let be the distance between the production well and the central well, in meters; The effective heating radius, in meters, is formed around the central well by the anhydrous self-generating heat material.

[0074] For any details not covered in this invention, please refer to the prior art.

[0075] The beneficial effects of this invention are as follows:

[0076] (1) Improved well network utilization efficiency and stage adaptability.

[0077] This invention employs a one-injection-four-production well network. The central well is initially used for fracturing and creating fractures and participating in depressurization production. Later, based on the decrease in gas production, the reduction in reservoir temperature, or the risk of secondary hydrate formation, the production is converted to injection to inject anhydrous self-generating heat materials. This allows the same central well to play the roles of permeability enhancement, gas production, and heat replenishment at different development stages, thereby improving the utilization efficiency of the well network.

[0078] (2) It improves the reservoir permeability and promotes the entry of anhydrous self-generating heat materials into the deep reservoir.

[0079] This invention utilizes a central well to fracturing and create artificial fractures in the target reservoir, forming a network of artificial fractures extending from the central well to four surrounding production wells. This enhances the permeability of low-permeability hydrate reservoirs, shallow gas reservoirs, or areas adjacent to both. Simultaneously, the artificial fracture network serves as a conduit for the later entry of anhydrous self-generating heat materials into the deeper reservoir, preventing excessive material accumulation near the wellbore and increasing the range of in-situ heat replenishment. Furthermore, when the anhydrous self-generating heat material is preferably a capsule-type material, the coating layer can isolate or delay water entry into the core material during wellbore transport, reducing the risk of premature heat release. After entering the artificial fracture network, the coating layer gradually opens under the influence of reservoir water infiltration, water swelling, fracture wall compression, or pore throat shearing, facilitating in-situ heat release into the deeper reservoir.

[0080] (3) It has achieved the stratified and coordinated extraction of shallow gas and natural gas hydrate decomposition gas.

[0081] This invention preferably places two opposing production wells in a natural gas hydrate reservoir and two other opposing production wells in a shallow gas reservoir, creating a more balanced depressurization sweep zone within the same reservoir. The shallow gas reservoir production wells can rapidly produce shallow gas, while the natural gas hydrate reservoir production wells can continuously produce hydrate decomposition gas under depressurization and in-situ reheating effects, thereby improving combined production efficiency and gas production sustainability.

[0082] (4) It reduces the risk of reservoir cooling and secondary hydrate formation blockage.

[0083] This invention, after initial production, injects anhydrous self-generating heat material into the artificial fracture network through a central well injection system based on changes in production and reservoir temperature. This allows the material to release heat in situ at depth within the reservoir, replenishing the heat required for hydrate decomposition, mitigating reservoir temperature drop, and increasing the temperature of artificial fractures, pore throats, near-wellbore zones, and gas migration channels. This reduces the risk of secondary hydrate formation and blockage under deep-water, low-temperature, and high-pressure conditions. Attached Figure Description

[0084] The accompanying drawings, which form part of this application, are used to provide a further understanding of this application. The illustrative embodiments of this application and their descriptions are used to explain this application and do not constitute an undue limitation of this application.

[0085] Figure 1 This is a schematic cross-sectional view of the efficient combined production system for deep-water shallow gas and natural gas hydrates of the present invention.

[0086] Figure 2 This is a schematic diagram of the planar layout of the one-injection-four-production well network and artificial fracture network of the present invention;

[0087] In the diagram, 1-Central well, 2-Second production well, 3-First production well, 4-Artificial fracture network, 5-In-situ exothermic zone, 6-Injection pipeline, 7-First generating fluid pipeline, 8-Second generating fluid pipeline, 9-Wellhead equipment, 10-Offshore platform, 11-Seawater layer, 12-Seabed mud surface, 13-Natural gas hydrate reservoir, 14-Shallow gas reservoir, 15-Underlying strata or interlayer, 16-Anhydrous autogenous heat material, 17-Third production well, 18-Fourth production well, 19-Secondary fracture network, 20-Artificial main fracture, 21-Target development area or co-production control area, 22-Distribution area of ​​anhydrous autogenous heat material. Detailed Implementation

[0088] To enable those skilled in the art to better understand the technical solutions in this specification, the technical solutions in the embodiments of this invention will be clearly and completely described below with reference to the accompanying drawings. However, this is not the only description; all aspects not described in detail herein are based on conventional techniques in the art.

[0089] Example 1

[0090] A highly efficient combined production system for deep-water shallow gas and natural gas hydrates, such as Figure 1 As shown, it includes an offshore platform 10, an injection pipeline 6, a wellhead device 9, a central well 1, production wells 3 arranged around the central well 1, and an artificial fracture network 4 extending from the central well to the target reservoir; the central well 1 passes through the seawater layer 11 and the seabed mud surface 12 and extends to the target reservoir area, which includes a natural gas hydrate reservoir 13 and a shallow gas reservoir 14; the shallow gas reservoir 14 is below an underlying stratum or interlayer 15.

[0091] One end of the central well and the production well are connected to the artificial fracture network. The other end of the central well is connected to the offshore platform via a wellhead device and an injection pipeline. The other end of the production well is connected to the offshore platform via a produced fluid pipeline. Figure 1 The first production well 2 is connected to the offshore platform through the first production fluid pipeline 7, and the second production well 3 is connected to the offshore platform through the second production fluid pipeline 8.

[0092] There are four production wells, which together with the central well form a four-injection well network. The central well is located in the center of the four-injection well network. The four production wells are distributed around the central well. Two of the wells are arranged opposite each other and are located in the same reservoir. The other two wells are also arranged opposite each other and are located in another reservoir.

[0093] An in-situ heat release zone is formed within the artificial fracture network by injecting anhydrous self-generating heat material 16.

[0094] This invention divides the four production wells into two groups, such as Figure 2 As shown, the production wells include a first production well 3, a second production well 2, a third production well 17, and a fourth production well 18. The first production well 3 and the third production well 17 are arranged opposite each other and located in the same reservoir, while the second production well 2 and the fourth production well 18 are arranged opposite each other and located in another reservoir. One set of opposite production wells is located in the natural gas hydrate reservoir 13, and the other set is located in the shallow gas reservoir 14. By arranging two production wells in the same reservoir opposite each other, a more balanced pressure reduction and diffusion zone can be formed within the corresponding reservoir, expanding the gas production range of the same layer. By arranging two sets of production wells from different reservoirs in a cross arrangement, both rapid shallow gas production and continuous gas supply from the decomposition of natural gas hydrates can be considered, thereby improving the efficiency and sustainability of combined production.

[0095] Compared to existing methods of simple depressurization or conventional heat injection, this invention combines central well fracturing and permeability enhancement, initial multi-well depressurization production, later central well production-to-injection conversion, in-situ heat replenishment with anhydrous self-generating materials, and a layered well network layout with one injection and four production stages. This allows the artificial fracture network to serve as both an initial gas production channel and a later transport channel for anhydrous self-generating materials to enter the deeper reservoir. This method fully leverages the effects of fracturing and permeability enhancement and multi-well depressurization gas production in the early stages of development, and provides on-demand heat replenishment based on production and reservoir temperature changes in the later stages of development. This improves the combined production efficiency, continuous gas production capacity, and production safety of deep-water shallow gas and natural gas hydrates.

[0096] Example 2

[0097] A high-efficiency combined production system for deep-water shallow gas and natural gas hydrates, as described in Example 1, differs in that the central well 1 is used in the early stage of development to inject fracturing fluid into the target reservoir to form an artificial fracture network, and participates in the initial depressurization production as a production well after fracturing is completed; after a period of production operation, depending on the decrease in gas production, the decrease in reservoir temperature, or the risk of secondary hydrate formation, the central well is converted from the production state to the injection state, and is used to inject anhydrous self-generating heat material into the artificial fracture network.

[0098] Preferably, the center well and production well are vertical, directional, or horizontal wells. For production wells in shallow gas reservoirs, their perforated sections, screen sections, or horizontal sections are preferably located within the shallow gas reservoir; for production wells in natural gas hydrate reservoirs, their perforated sections, screen sections, or horizontal sections are preferably located within the natural gas hydrate reservoir. The center well preferably penetrates the shallow gas reservoir and extends into the natural gas hydrate reservoir or the adjacent zone or connecting section between the two, so as to form an artificial fracture network that connects across or near layers during fracturing.

[0099] This invention first utilizes a central well to fracturing shallow gas reservoirs, natural gas hydrate reservoirs, and adjacent or connected zones between shallow gas and natural gas hydrates, forming an artificial fracture network extending from the central well to four surrounding production wells. After fracturing, the central well does not immediately inject anhydrous self-generating heat material; instead, it works in conjunction with the four surrounding production wells to perform initial depressurization production, fully utilizing the high permeability channels created after fracturing to rapidly extract shallow gas and some hydrate decomposition gas. After a period of production operation, if the gas production is detected to drop below a preset threshold, or if the reservoir temperature is detected to drop below a preset temperature threshold, the central well is switched from production to injection mode, and anhydrous self-generating heat material is injected into the artificial fracture network through the central well.

[0100] Example 3

[0101] A high-efficiency combined production system for deep-water shallow gas and natural gas hydrates, as described in Example 2, differs in that the anhydrous self-generating heat material 16 is a capsule-type anhydrous self-generating heat material, comprising a core material and a coating layer. The core material is an anhydrous material that releases heat upon contact with water. The coating layer is used to isolate or delay the entry of water into the core material during the wellbore transport stage, reducing the risk of premature heat release from the core material. The anhydrous self-generating heat material enters the deep reservoir along artificial fractures and the pores around the fractures. When the anhydrous self-generating heat material is a capsule-type anhydrous self-generating heat material, the coating layer gradually opens under the action of reservoir water infiltration, water swelling, fracture wall compression, or pore throat shearing, allowing the core material to react exothermically with reservoir water, residual fracturing fluid, or decomposition water of natural gas hydrates. This releases heat in situ within the reservoir, replenishing the heat required for hydrate decomposition, promoting further hydrate decomposition, and reducing the risk of secondary hydrate formation during gas migration.

[0102] The core material is a calcium oxide-based anhydrous exothermic material;

[0103] The heat release principle of anhydrous self-generating materials is as follows: Upon contact with reservoir water, residual fracturing fluid, or decomposition water from natural gas hydrates, the core material undergoes a hydration or redox reaction, releasing heat. Taking calcium oxide-based anhydrous exothermic materials as an example, upon contact with water, it undergoes a hydration reaction to generate calcium hydroxide and release heat. The coating layer is used to isolate or delay the entry of moisture into the core material during wellbore transport, reducing the risk of premature and significant exothermic reactions occurring within the wellbore.

[0104]

[0105] The anhydrous self-generating heat material is carried into the artificial fracture network and the pores surrounding the fractures by a low-water-content carrier fluid. The low-water-content carrier fluid is used to suspend, disperse, and transport the anhydrous self-generating heat material. The low-water-content carrier fluid refers to a carrier fluid with a low water content that does not cause significant premature exothermic reactions in the anhydrous self-generating heat material during wellbore transport. Preferably, the water content of the low-water-content carrier fluid is not higher than 10%, and more preferably not higher than 5%.

[0106] Preferably, when the anhydrous self-generating material is a capsule-type anhydrous self-generating material, after the capsule-type anhydrous self-generating material enters the artificial fracture network with the low water content carrying liquid, its coating layer gradually opens under the action of reservoir water infiltration, water swelling, fracture wall compression or pore throat shearing, so that the core material comes into contact with reservoir water, residual fracturing fluid or natural gas hydrate decomposition water and undergoes an exothermic reaction.

[0107] To reduce the risk of anhydrous self-generating heat materials clogging the artificial fracture network, the particle size of the anhydrous self-generating heat material was determined based on the minimum effective aperture of the artificial fractures before injection. The material injection concentration, low-water-content carrier liquid discharge rate, and injection pressure were also controlled. The particle size of the anhydrous self-generating heat material met the following requirements. ,in This represents the particle size, in mm, corresponding to a cumulative throughput of 90% in the particle size distribution of the anhydrous self-generating heat material. This indicates the minimum effective aperture of the artificial crack, in mm. This indicates the anti-bridging multiple, ranging from 3 to 5. Through the above particle size matching relationship, the risk of material bridging at the fracture entrance or near-wellbore zone can be reduced, and the material's ability to penetrate deep into the fracture network can be improved.

[0108] After entering the artificial fracture network, the anhydrous self-generating heat material migrates or remains on the fracture wall in a dispersed particle state. Its reaction products are preferably present in a dispersed, porous or locally attached state, which does not completely block the artificial fracture network, thereby ensuring that the subsequent shallow gas and hydrate decomposition gas can still migrate to the production well along the artificial fracture network.

[0109] The anhydrous autogenous thermal material and the low-water-cut carrying fluid have a dispersed transport relationship. The anhydrous autogenous thermal material is dispersed as a solid dispersed phase in the low-water-cut carrying fluid, which acts as a continuous phase. Under the influence of the injection pressure differential, the low-water-cut carrying fluid carries the anhydrous autogenous thermal material sequentially through the central wellbore, perforation holes, artificial primary fractures, and secondary fracture networks into the target reservoir. The low-water-cut carrying fluid mainly serves to suspend, disperse, and transport the material; it is not the primary exothermic component.

[0110] Preferably, after fracturing the central well 1, the artificial main fracture 9 extends from the central well 1 towards the four production wells, forming a secondary fracture network 19 within the target development area or joint production control area 21. The extension direction of the artificial main fracture 20 can be controlled by the arrangement of the four production wells, the direction of the maximum horizontal principal stress of the target reservoir, the perforation azimuth of the central well, the location of the staged fracturing, and the fracturing flow rate. Preferably, the arrangement of the four production wells is matched with the dominant seepage direction or the direction of the maximum horizontal principal stress of the target reservoir, and directional perforation or staged fracturing is performed at the corresponding azimuth of the central well, so that the artificial main fracture 20 preferentially extends towards the four production wells.

[0111] Artificial fracture networks are used to improve the permeability of low-permeability hydrate reservoirs, shallow gas reservoirs, or areas adjacent to both, to form high-permeability channels for the migration of shallow gas and hydrate decomposition gas to production wells, and to provide channels for the entry of anhydrous autothermal materials into deeper reservoirs in the later stages.

[0112] Secondary fracture network 19 can be formed by increasing the net fracturing pressure, using proppant-carrying fracturing fluid to support the fracture, temporarily plugging the directional fracturing, repeating fracturing, or re-opening the natural weak surface of the reservoir. This can generate branch fractures, induced fractures, or re-opening of natural fractures around the artificial main fracture 9, thereby increasing the migration channels of anhydrous autothermal materials and produced gas.

[0113] In the early stages of development, the central well 1 and four production wells jointly participated in depressurization production. In the later stages of development, when production declined, reservoir temperature decreased, or the risk of secondary hydrate formation increased, the central well 1 switched from production to injection. The anhydrous self-generating heat material 16 entered the deep part of the target reservoir along the artificial main fracture 20 and the secondary fracture network 19, forming an anhydrous self-generating heat material distribution zone 22 between the central well 1 and the four production wells. The anhydrous self-generating heat material 16 is a capsule-type anhydrous self-generating heat material. During the wellbore transportation stage, the coating layer isolates or delays the entry of water into the core material. After entering the artificial main fracture 20 and the secondary fracture network 19, it gradually opens through reservoir water infiltration, water swelling, fracture wall compression, or pore throat shearing, thereby achieving in-situ heat replenishment and continuous co-production.

[0114] Example 4

[0115] A high-efficiency combined production system for deep-water shallow gas and natural gas hydrates, as described in Example 3, differs in that the combined production system also includes a production well depressurization control unit and a monitoring and control unit. The production well depressurization control unit is used to control the bottom hole pressure of four production wells and the initial central well. The four production wells can be produced using synchronous depressurization, step-by-step depressurization, staged depressurization, or stratified differentiated depressurization methods. Preferably, production wells located in shallow gas reservoirs can first undergo a larger depressurization to quickly produce shallow gas; production wells located in natural gas hydrate reservoirs adopt a step-by-step depressurization method to reduce the risks of reservoir instability, sand production, and sudden increases in water production.

[0116] The monitoring and control unit is used to monitor the target reservoir temperature, bottom hole pressure of the central well and four production wells, gas production, water production, wellbore pressure, wellbore temperature, and the risk of secondary hydrate formation. Based on the monitoring results, it determines the timing of production-to-injection conversion of the central well, the amount and timing of injection of anhydrous self-generating heat material, the pressure reduction range and rate of pressure reduction of the four production wells, and the start-up and shutdown sequence of each well.

[0117] The monitoring and control unit includes downhole pressure sensors, downhole temperature sensors, distributed fiber optic temperature sensors, wellhead pressure sensors, wellhead temperature sensors, gas flow meters, liquid flow meters, sand-bearing monitoring devices, and data acquisition and control modules.

[0118] Downhole pressure and temperature sensors are respectively deployed in the target formations of the central well and the four production wells to acquire bottom hole pressure and temperature. Distributed fiber optic temperature sensors are deployed along the wellbore of the central well and production wells to acquire temperature distribution in the wellbore and near-wellbore area. Wellhead pressure and temperature sensors are installed at the wellhead equipment to acquire wellhead pressure and temperature. Gas and liquid flow meters are installed at the gas and liquid phase outlets, respectively, to acquire gas and water production rates. A sand-bearing monitoring device is installed in the produced fluid pipeline to assess sand production risk. The data acquisition and control module receives temperature, pressure, flow rate, and sand production risk monitoring data, and adjusts the timing of production-to-injection conversion in the central well, the injection volume of anhydrous self-heating material, and the depressurization of the production wells accordingly.

[0119] Example 5

[0120] A method for efficient combined production of deep-water shallow gas and natural gas hydrates, implemented through a particle 4 efficient combined production system for deep-water shallow gas and natural gas hydrates, includes the following steps:

[0121] S1, identify deep-water shallow gas reservoirs, natural gas hydrate reservoirs and their spatial relationships in the target sea area, and determine the target development area;

[0122] Based on seismic data, well logging data, geological sampling data, formation pressure data, temperature data, and test production data of the target sea area, the deep-water shallow gas reservoirs, natural gas hydrate reservoirs, and their spatial relationships are determined. Spatial relationships include the coexistence, association, vertical proximity, lateral proximity, or interconnection through connecting segments between shallow gas reservoirs and natural gas hydrate reservoirs.

[0123] S2. After determining the target development area, a central well 1 is arranged in the target development area, and four production wells are arranged around the central well to form a one-injection-four-production well network. Among them, two production wells arranged opposite each other are located in the natural gas hydrate reservoir 13, and the other two production wells arranged opposite each other are located in the shallow gas reservoir 14. Through this arrangement, the two production wells in the same reservoir are distributed opposite each other, which is conducive to forming a relatively balanced pressure reduction and sweeping zone in the corresponding reservoir. The production wells in different reservoirs are distributed in a cross pattern, which is conducive to simultaneously controlling the shallow gas reservoir and the natural gas hydrate reservoir.

[0124] S3, after the well network layout is completed, fracturing fluid is injected into the target reservoir through the central well to create artificial fractures in shallow gas reservoirs, natural gas hydrate reservoirs, adjacent areas, coexisting areas or connected sections of shallow gas and natural gas hydrates, forming an artificial fracture network extending from the central well to the four surrounding production wells.

[0125] For production wells arranged in layers, production wells located in shallow gas reservoirs are preferably completed in the shallow gas reservoir, and production wells located in natural gas hydrate reservoirs are preferably completed in the natural gas hydrate reservoir; if necessary, production wells can also be extended to the corresponding target layer through directional or horizontal sections.

[0126] S4. After fracturing is completed, the central well is not immediately injected with anhydrous self-generating heat material, but participates in the initial depressurization production as a production well. At the same time, the four surrounding production wells carry out stratified depressurization production of shallow gas reservoirs and natural gas hydrate reservoirs, so that shallow gas, hydrate decomposition gas and formation water are collected and extracted to the central well and surrounding production wells.

[0127] S5, during the initial production process, monitor the gas production, water production, bottom hole pressure, wellbore temperature, reservoir temperature, and risk of secondary hydrate formation in the central well and four production wells; when the gas production drops below the preset gas production threshold, the reservoir temperature drops below the preset temperature threshold, or the risk of secondary hydrate formation reaches the preset risk threshold, the central well is switched from production state to injection state.

[0128] S6. After the central well is converted to the injection state, anhydrous self-generating heat material is injected into the artificial fracture network and the pores around the fractures through the central well. The anhydrous self-generating heat material 16 enters the artificial fracture network with the low water content carrying liquid.

[0129] S7, after the anhydrous self-generating heat material enters the artificial fracture network, it undergoes an exothermic reaction upon contact with reservoir water, residual fracturing fluid, or decomposition water of natural gas hydrates, releasing heat in situ inside the target reservoir.

[0130] During or after the injection of anhydrous self-generating heat material into the central well (S8), the four surrounding production wells continue to depressurize and produce gas. This allows the shallow gas to continue flowing into the shallow gas reservoir production wells under the pressure difference and be extracted. The natural gas hydrate continues to decompose under the combined action of depressurization and in-situ heating. The resulting hydrate decomposition gas is collected and extracted into the natural gas hydrate reservoir production wells. The produced shallow gas, hydrate decomposition gas, and formation water are then collected and transported after gas-liquid separation.

[0131] Example 6

[0132] A highly efficient method for the combined production of deep-water shallow gas and natural gas hydrates, as described in Example 5, except that in step S3, the fracturing fluid is seawater, fresh water, low-damage fracturing fluid, proppant-carrying fracturing fluid, or a combination thereof.

[0133] During fracturing, the fracturing pressure is greater than the target reservoir initiation pressure and controlled within the formation safety pressure range to form an artificial fracture network extending from the central well to the four surrounding production wells. This artificial fracture network serves two purposes: firstly, it enhances the permeability of low-permeability hydrate reservoirs and shallow gas reservoirs, increasing the migration capacity of shallow gas and hydrate decomposition gas; secondly, it provides pathways for the subsequent entry of anhydrous autothermal materials into the deeper parts of the reservoir.

[0134] Central well 1 participates in the initial depressurization production as a production well. After a period of production operation, when the gas production drops below the preset gas production threshold, the reservoir temperature drops below the preset temperature threshold, or the risk of secondary hydrate formation reaches the preset risk threshold, central well 1 is switched from production state to injection state, and anhydrous self-generating heat material is injected into the artificial fracture network 4 through the anhydrous self-generating heat material injection pipeline 6, so as to form an in-situ exothermic zone 5 in the target reservoir.

[0135] Example 7

[0136] An efficient method for the combined production of deep-water shallow gas and natural gas hydrate, as described in Example 6, differs in that, in step S4, two production wells located in the shallow gas reservoir preferentially produce shallow gas, two production wells located in the natural gas hydrate reservoir reduce the hydrate reservoir pressure and promote the decomposition of natural gas hydrate, and the central well assists in the production of shallow gas, hydrate decomposition gas and formation water in the interconnected area after fracturing.

[0137] Example 8

[0138] An efficient method for the combined production of deep-water shallow gas and natural gas hydrate, as described in Example 7, differs in that, in step S5, during the initial production process, the production wells located in the shallow gas reservoir adopt a relatively large pressure reduction range to quickly form shallow gas discharge channels and increase early gas production; the production wells located in the natural gas hydrate reservoir preferably adopt a step-by-step pressure reduction method to reduce the risk of sand production, sudden increase in water production, or formation instability in the hydrate reservoir;

[0139] No. The bottom pressure of the production well during each depressurization stage can be expressed as:

[0140]

[0141] in, For the first Bottom hole pressure of production wells during each depressurization stage, MPa; This refers to the bottom hole pressure of the production well in the previous depressurization stage, in MPa. For the first The depressurization range of each depressurization stage, in MPa; the depressurization range is determined based on reservoir stability, water production, sand production risk, and hydrate decomposition requirements.

[0142] The bottom hole pressure of the production well is determined based on the target reservoir temperature and the phase equilibrium pressure of natural gas hydrate. For natural gas hydrate in the target reservoir, its phase equilibrium pressure can be determined based on the reservoir temperature according to the following empirical relationship:

[0143]

[0144] in, For natural gas hydrates at reservoir temperature The phase equilibrium pressure at the specified point, in MPa; Reference pressure, MPa; Let A be the absolute temperature of the reservoir, in K; and B be the fitting coefficients related to the natural gas composition, formation water salinity, and target reservoir conditions, where A is dimensionless and B is in K. The fitting coefficients A and B can be obtained by fitting experimental data on the natural gas composition, formation water salinity, and hydrate phase equilibrium of the target block. Alternatively, they can be initially determined based on experimental data from adjacent blocks, hydrate phase equilibrium calculation software, or publicly available phase equilibrium charts, and then corrected using field test production temperature and pressure data. Since A and B are significantly affected by gas composition, formation water salinity, and pressure units, it is preferable to calibrate them using experimental or test production data during implementation in specific blocks.

[0145] To promote the decomposition of natural gas hydrates, the bottom hole pressure of production wells located in natural gas hydrate reservoirs should preferably meet the following requirements:

[0146] in, The bottom pressure of the production well, in MPa; The reservoir temperature (K) within the control area of ​​the production well; For temperature The equilibrium pressure of the hydrate phase at the specified depth, MPa; The safe pressure reduction differential to promote stable decomposition of hydrates is MPa;

[0147] As production proceeds, shallow gas preferentially flows to and is extracted from production wells located in shallow gas reservoirs under the influence of pressure differential. Natural gas hydrates gradually decompose under depressurization, and the resulting hydrate decomposition gas converges and is extracted from production wells and central wells located in natural gas hydrate reservoirs. The shallow gas, hydrate decomposition gas, and formation water produced by the production wells are separated by gas-liquid separation devices at the wellhead, subsea production facilities, or surface platforms. The separated natural gas enters the gathering and transportation system, while the produced water is treated before being discharged, reinjected, or recycled as a carrier fluid.

[0148] During the initial production process, the gas production, water production, bottom hole pressure, wellbore temperature, reservoir temperature, and risk of secondary hydrate formation were monitored in the central well and the four surrounding production wells.

[0149] The decomposition rate of natural gas hydrate reservoirs can be obtained by comprehensively considering changes in gas production, hydrate saturation, and reservoir temperature. Gas production changes are obtained using gas flow meters; hydrate saturation changes can be obtained through resistivity logging, sonic logging, temperature-pressure inversion, or production dynamics fitting; reservoir temperature changes are obtained using downhole temperature sensors or distributed fiber optic temperature sensors. The gas production threshold is determined based on the initial stable gas production. When the current gas production drops to 30%-70% of the initial stable gas production and remains so for 3-7 days, the gas production threshold is considered to have been reached.

[0150] The criterion for a decrease in gas production can be expressed by the following relationship:

[0151]

[0152] in, For production time Gas production rate at that time, m³ / d; To ensure a stable initial gas production rate, m³ / d; This is the threshold coefficient for gas production decline, which is dimensionless and... .

[0153] The criterion for reservoir temperature reduction can be expressed by the following relationship:

[0154]

[0155] in, For production time The reservoir temperature at that time, in K; The initial reservoir temperature or the reservoir temperature during the initial stable production stage, in K; The critical temperature drop K is required to trigger the conversion of the central well to injection.

[0156] The temperature threshold is determined based on the initial reservoir temperature or the reservoir temperature during the initial stable production stage. The temperature threshold is the temperature that decreases by 2-3K compared to the initial stable production stage.

[0157] The risk threshold for secondary hydrate formation can be determined based on the degree of similarity between the measured pressure and temperature within the gas migration channel and the hydrate phase equilibrium conditions. or At that time, it was considered that the risk threshold for secondary hydrate formation had been reached, among which Represents any position in the gas transport channel Pressure at the location, Indicates temperature The equilibrium pressure of the hydrate phase below; This indicates any position in the gas transport channel. The temperature at that location Indicates pressure The equilibrium temperature of the hydrate phase, K; This represents the safe temperature margin (K) to prevent secondary hydrate formation. The value can be determined based on the hydrate phase equilibrium conditions of the target block, the temperature and pressure fluctuation range of the wellbore, and the production safety requirements. The value range can be 1-5K, preferably 2-3K.

[0158] In this embodiment, the location is considered to have a risk of secondary hydrate formation when the following conditions are met:

[0159]

[0160] To reduce the risk of secondary hydrate formation, the gas migration channel temperature can be adjusted by supplementing with anhydrous self-generating heat-generating materials, adjusting the pressure reduction of production wells, or changing the start-up and shutdown sequence of production wells.

[0161]

[0162] When a rapid decline in reservoir temperature, a continued significant decrease in gas production, or an increased risk of secondary hydrate formation is detected, anhydrous autogenous heating materials can be periodically injected into the central well to enhance the continuous heating capacity within the target reservoir. When a rapid increase in water production, an increased risk of sand production, or a rise in formation stability risk is detected, the depressurization rate of production wells can be reduced, the magnitude of single-stage depressurization can be decreased, or production from some production wells can be suspended. These methods can improve the combined production efficiency of deep-water shallow gas and natural gas hydrates while reducing the risks of reservoir instability, wellbore blockage, and secondary hydrate formation.

[0163] Example 9

[0164] A highly efficient method for the combined production of deep-water shallow gas and natural gas hydrates, as described in Example 8, differs in that, in step S6, the injection amount of anhydrous self-generating heat material is determined based on the heat required for the decomposition of natural gas hydrates in the target heating area, the heat required for reservoir heating, and the heat release per unit mass of the anhydrous self-generating heat material.

[0165] The heat required for the decomposition of natural gas hydrates within the target heating zone can be determined using the following formula:

[0166]

[0167] in, This represents the heat absorbed during the decomposition of natural gas hydrates, in J; The amount of natural gas released from the decomposition of hydrates within the target heating area is expressed in mol. The enthalpy of decomposition of natural gas hydrate, expressed as a unit amount of substance, is J / mol.

[0168] The amount of heat required to raise the reservoir temperature is determined by the following formula:

[0169]

[0170] in, The amount of heat required to heat the reservoir, J; The reservoir skeleton density is expressed in kg / m³. 3 ; is the specific heat capacity of the reservoir framework, J / (kg·K); Let m be the reservoir skeleton volume within the target heating region. 3 ; Density of formation water, kg / m³ 3 ; is the specific heat capacity of formation water, J / (kg·K); Let m be the volume of formation water within the target heating area. 3 ; The initial reservoir temperature is given in °C. Target reservoir temperature, °C;

[0171] Therefore, the theoretical injection mass of the anhydrous self-generating heat material can be determined by the following formula:

[0172]

[0173] in, The theoretical injection mass of the anhydrous self-generating heat material, in kg; The heat release per unit mass of the anhydrous self-generating material is expressed in J / kg; when the anhydrous self-generating material is a capsule-type anhydrous self-generating material... The equivalent heat release per unit mass of capsule-type anhydrous self-generating heat material, J / kg; This is the in-situ heat utilization coefficient, which is dimensionless. The value can be determined based on reservoir heat loss, fracture development, material distribution, and reservoir heterogeneity, and can range from 0.3 to 0.8, preferably 0.4 to 0.6. The lower the reservoir heat loss, the more uniform the material distribution, and the better the fracture connectivity, the better the results. The larger the value;

[0174] Preferably, in actual construction, the theoretical injection quality can be modified based on reservoir heterogeneity, fracture development, material migration capacity, and heat loss.

[0175]

[0176] in, The actual injected mass of the anhydrous self-generating heat material is expressed in kg. For the injection correction coefficient, dimensionless, and Inject correction coefficient The value can be determined based on reservoir heterogeneity, fracture connectivity, material migration capacity, and heat loss, and can range from 1.1 to 2.0, preferably 1.2 to 1.5. The stronger the reservoir heterogeneity, the worse the fracture connectivity, the longer the material migration distance, or the greater the heat loss, the better. The larger the value, the better.

[0177] In step S6, the low-water-content carrier liquid is used to suspend, disperse, and transport the anhydrous self-generating heat material.

[0178] The anhydrous self-generating heat material is a capsule-type anhydrous self-generating heat material. The coating layer of this capsule-type anhydrous self-generating heat material gradually opens under the influence of reservoir water infiltration, water swelling, fracture wall compression, or pore throat shearing, exposing the core material and allowing it to contact and release heat with reservoir water, residual fracturing fluid, or decomposition water from natural gas hydrates. The released heat is transferred to the surrounding natural gas hydrate reservoir through the artificial fracture walls, surrounding pores, and reservoir pores, increasing the reservoir temperature, replenishing the heat required for the endothermic decomposition of natural gas hydrates, and promoting the continued decomposition of natural gas hydrates into natural gas and water.

[0179] During the wellbore transport stage, the anhydrous self-generating thermal material is isolated or has its moisture ingress into the core material by a coating layer, and gradually opens up after entering the artificial fracture network. By controlling the particle size of the anhydrous self-generating thermal material, the discharge rate of the low water-cut carrying fluid, the injection pressure, and the bottom hole pressure of the four production wells, the anhydrous self-generating thermal material is transported along the artificial main fracture and secondary fracture network toward the four production wells and distributed in the target area between the central well and the four surrounding production wells.

[0180] The distribution of anhydrous autogenous heat-generating materials in the target area between the central well and the four production wells can be improved through the following methods: First, during the fracturing stage, the artificial main fracture should be preferentially extended towards the four production wells; second, the particle size of the anhydrous autogenous heat-generating material should be controlled according to the opening of the artificial fracture to enable it to penetrate into the deep part of the fracture; third, the discharge rate of low water-cut carrying fluid, the injection rate of material, and the injection pressure should be determined according to the volume of the artificial fracture and the target heating range; fourth, the bottom hole pressure of the four production wells should be appropriately reduced during the injection process to form a directional pressure gradient between the central well and the four production wells, guiding the low water-cut carrying fluid and the anhydrous autogenous heat-generating material to migrate towards the four production wells; fifth, the dispersion of the material in the artificial fracture network can be improved by using batch injection, pulse injection, or periodic supplementary injection methods.

[0181] Example 10

[0182] A highly efficient method for the combined production of deep-water shallow gas and natural gas hydrates, as described in Example 9, differs in that, in step S8, during or after the injection of anhydrous self-generating heat material into the central well, four surrounding production wells continue depressurization production. Specifically, the production wells located in the shallow gas reservoir continue to produce shallow gas, while the production wells located in the natural gas hydrate reservoir continuously produce hydrate decomposition gas under the combined effects of depressurization and in-situ reheating. Because the artificial fracture network connects the central well and the surrounding production wells, the heat released by the anhydrous self-generating heat material can be transferred along the fracture network to the surrounding hydrate reservoirs, thereby increasing the temperature in the hydrate decomposition zone and mitigating the reservoir temperature drop.

[0183] To ensure that the pressure-reducing sweep area of ​​the surrounding production wells overlaps with the fracture network and the heat release area of ​​the anhydrous self-generating material formed by the central well, the well spacing between the production wells and the central well can be determined based on the reservoir pressure diffusion characteristics. The pressure-reducing sweep radius of the production well can be determined using the following approximate relationship:

[0184]

[0185] in, For production wells during production time The radius of the voltage drop wave, in meters; m is the reservoir permeability. 2 ; Reservoir porosity, dimensionless; The viscosity of the fluid is Pa·s; The overall compression factor is Pa⁻¹; Pressure wave correction factor, dimensionless; overall compressibility factor. Pressure wave correction factor can be determined through core compression tests, well test interpretation, pressure recovery tests, or data from adjacent blocks; when measured data is lacking, preliminary estimates can be made using parameters from adjacent blocks or similar reservoirs. The value used to account for the effects of fracture networks, reservoir heterogeneity, multiphase flow, and boundary conditions on pressure propagation can be obtained through well test interpretation, numerical simulation, or tracer testing correction. A value of 1-4 can be used in the initial engineering calculation.

[0186] Well spacing between production wells and center wells Preferred satisfaction:

[0187]

[0188] in, Let be the distance between the production well and the central well, in meters; The effective heating radius, in meters, is formed around the central well by the anhydrous self-generating heat material. Through the aforementioned well spacing matching method, the depressurization zone of the production well, the artificial fracture connectivity zone, and the heat release zone of the anhydrous self-generating heat material can effectively overlap, improving the extraction efficiency of shallow gas and natural gas hydrate decomposition gas.

[0189] The above description represents the preferred embodiments of the present invention. It should be noted that those skilled in the art can make various improvements and modifications without departing from the principles of the present invention, and these improvements and modifications should also be considered within the scope of protection of the present invention.

Claims

1. A high-efficiency combined production system for deepwater shallow gas and natural gas hydrates, characterized in that, It includes offshore platforms, injection pipelines, wellhead equipment, central wells, production wells arranged around the central wells, and a network of artificial fractures extending from the central wells to the target reservoirs; the central wells pass through the seawater layer and the seabed mud surface and extend to the target reservoir area, which includes natural gas hydrate reservoirs and shallow gas reservoirs. One end of the central well and the production well are connected to the artificial fracture network, the other end of the central well is connected to the offshore platform through a wellhead device and an injection pipeline, and the other end of the production well is connected to the offshore platform through a production fluid pipeline. The number of production wells is four, forming a four-injection well network with the central well. The central well is located at the center of the four-injection well network, and the four production wells are distributed around the central well. Two of the wells are arranged opposite each other and located in the same reservoir, while the other two wells are also arranged opposite each other and located in another reservoir. An in-situ heat release zone is formed within the artificial fracture network by injecting anhydrous self-generating heat material.

2. The high-efficiency commingling production system of deepwater shallow gas and natural gas hydrates according to claim 1, characterized in that, The central well is used in the early stages of development to inject fracturing fluid into the target reservoir area to form an artificial fracture network. After fracturing is completed, the central well and the four production wells participate in the initial depressurization production. After a period of production operation, the central well is converted from production state to injection state. Preferably, the central well and the production well are vertical wells, directional wells, or horizontal wells.

3. The high-efficiency commingling production system of deepwater shallow gas and natural gas hydrates according to claim 2, characterized in that, The waterless self-generating heat material is a capsule-type waterless self-generating heat material, including a core material and a coating layer. The core material is a waterless material that releases heat when it comes into contact with water. The coating layer is used to isolate or delay the entry of water into the core material during the wellbore transportation stage. The core material is one or more of the following: calcium oxide, magnesium oxide, calcium-based composite heat-generating material, magnesium-based composite heat-generating material, and aluminum-based composite heat-generating material. Preferably, the particle size of the anhydrous self-heating material satisfies wherein D90 represents the particle size corresponding to a cumulative passing rate of 90% in the particle size distribution of the anhydrous self-heating material, mm; Dmin represents the minimum effective opening of the artificial fracture, mm, the bridge plugging prevention multiple is 3-5. Preferably, the artificial fracture network is formed by fracturing in the central well, including artificial main fractures and secondary fractures. The artificial main fractures extend from the central well toward the four production wells. The secondary fracture network is formed by increasing the net fracturing pressure, using sand-carrying fracturing fluid to support the fractures, temporarily plugging and redirecting fracturing, repeated fracturing, or re-opening the natural weak surface of the reservoir.

4. The high-efficiency combined production system for deep-water shallow gas and natural gas hydrates according to claim 3, characterized in that, It also includes a monitoring and control unit, used to monitor the target reservoir temperature, bottom hole pressure of the central well and four production wells, gas production, water production, wellbore pressure, wellbore temperature, and the risk of secondary hydrate formation; The monitoring and control unit includes a downhole pressure sensor, a downhole temperature sensor, a distributed fiber optic temperature sensor, a wellhead pressure sensor, a wellhead temperature sensor, a gas flow meter, a liquid flow meter, a sand-bearing monitoring device, and a data acquisition and control module. The downhole pressure and temperature sensors are respectively arranged in the target formations of the central well and the four production wells to obtain bottom hole pressure and temperature. The distributed fiber optic temperature sensors are deployed along the wellbore of the central well and the production wells to obtain the temperature distribution in the wellbore and near-wellbore area. The wellhead pressure and temperature sensors are installed at the wellhead device to obtain wellhead pressure and temperature. The gas flow meter and liquid flow meter are respectively installed at the gas phase outlet and liquid phase outlet to obtain gas production and water production. The sand-bearing monitoring device is installed in the produced fluid pipeline to determine the sand production risk. The data acquisition and control module is used to receive temperature, pressure, flow rate, and sand production risk monitoring data, and adjust the timing of production-to-injection conversion in the central well, the injection volume of anhydrous self-generating heat material, and the depressurization of the production wells accordingly.

5. A method for efficient combined extraction of deep-water shallow gas and natural gas hydrates, characterized in that, The efficient combined production system for deep-water shallow gas and natural gas hydrates as described in claim 4 includes the following steps: S1, Identify deep-water shallow gas reservoirs, natural gas hydrate reservoirs, and their spatial relationships in the target sea area to determine the target development area; the spatial relationships include coexistence, association, vertical proximity, lateral proximity, or interconnection through connecting segments between shallow gas reservoirs and natural gas hydrate reservoirs. S2 involves deploying a central well in the target development area and four production wells around the central well to form a network of one injection and four production wells. Two of the production wells are located in the natural gas hydrate reservoir, while the other two are located in the shallow gas reservoir. S3 involves injecting fracturing fluid into the target reservoir through the central well to create artificial fractures in shallow gas reservoirs, natural gas hydrate reservoirs, adjacent areas, coexisting areas, or connected sections of shallow gas and natural gas hydrates, forming an artificial fracture network extending from the central well to the four surrounding production wells. S4. After fracturing is completed, the central well is not immediately injected with anhydrous self-generating heat material, but participates in the initial depressurization production as a production well. At the same time, the four surrounding production wells carry out stratified depressurization production of shallow gas reservoirs and natural gas hydrate reservoirs, so that shallow gas, hydrate decomposition gas and formation water are collected and extracted to the central well and surrounding production wells. S5, during the initial production process, monitor the gas production, water production, bottom hole pressure, wellbore temperature, reservoir temperature, and risk of secondary hydrate formation in the central well and four production wells; when the gas production drops below the preset gas production threshold, the reservoir temperature drops below the preset temperature threshold, or the risk of secondary hydrate formation reaches the preset risk threshold, the central well is switched from production state to injection state. S6. After the central well is converted to the injection state, anhydrous self-generating heat material is injected into the artificial fracture network and the pores around the fractures through the central well. The anhydrous self-generating heat material enters the artificial fracture network with the low water content carrying liquid. S7, after the anhydrous self-generating heat material enters the artificial fracture network, it undergoes an exothermic reaction upon contact with reservoir water, residual fracturing fluid, or decomposition water of natural gas hydrates, releasing heat in situ inside the target reservoir. During or after the injection of anhydrous self-generating heat material into the central well (S8), the four surrounding production wells continue to depressurize and produce gas. This allows the shallow gas to continue flowing into the shallow gas reservoir production wells under the pressure difference and be extracted. The natural gas hydrate continues to decompose under the combined action of depressurization and in-situ heating. The resulting hydrate decomposition gas is collected and extracted into the natural gas hydrate reservoir production wells. The produced shallow gas, hydrate decomposition gas, and formation water are then collected and transported after gas-liquid separation.

6. The method for efficient combined production of deep-water shallow gas and natural gas hydrates according to claim 5, characterized in that, In step S3, the fracturing fluid is seawater, fresh water, low-damage fracturing fluid, proppant-carrying fracturing fluid, or a combination thereof; During fracturing, the fracturing pressure is greater than the target reservoir initiation pressure and is controlled within the formation safety pressure range.

7. The method for efficient combined production of deep-water shallow gas and natural gas hydrates according to claim 6, characterized in that, In step S4, the two production wells located in the shallow gas reservoir prioritize the production of shallow gas, the two production wells located in the natural gas hydrate reservoir reduce the pressure of the hydrate reservoir and promote the decomposition of natural gas hydrate, and the central well assists in the production of shallow gas, hydrate decomposition gas and formation water in the fracturing interconnected area.

8. The method for efficient combined production of deep-water shallow gas and natural gas hydrates according to claim 7, characterized in that, In step S5, during the initial production process, production wells located in shallow gas reservoirs adopt a large depressurization range to quickly form shallow gas venting channels and increase early gas production; production wells located in natural gas hydrate reservoirs adopt a step-by-step depressurization method to reduce the risk of sand production, sudden increase in water production, or formation instability in hydrate reservoirs. In step S5, the gas production threshold is determined based on the initial stable gas production. When the current gas production drops to 30%-70% of the initial stable gas production and continues for 3-7 days, the gas production threshold is considered to have been reached. The temperature threshold is determined based on the initial reservoir temperature or the reservoir temperature during the initial stable production stage. The temperature threshold is the temperature that decreases by 2-3K compared to the initial stable production stage. when or At that time, it was considered that the risk threshold for secondary hydrate formation had been reached, among which Represents any position in the gas transport channel Pressure at the location, Indicates temperature The equilibrium pressure of the hydrate phase below; This indicates any position in the gas transport channel. The temperature at that location Indicates pressure The equilibrium temperature of the hydrate phase, K; K represents the safe temperature margin to prevent the secondary formation of hydrates.

9. The method for efficient combined production of deep-water shallow gas and natural gas hydrates according to claim 8, characterized in that, In step S6, the amount of anhydrous self-generating heat material injected is determined based on the heat required for the decomposition of natural gas hydrates in the target heating area, the heat required for reservoir heating, and the heat release per unit mass of the anhydrous self-generating heat material. The heat required for the decomposition of natural gas hydrates within the target heating area is determined by the following formula: in, This represents the heat absorbed during the decomposition of natural gas hydrates, in J; The amount of natural gas released from the decomposition of hydrates within the target heating area is expressed in mol. The enthalpy of decomposition of natural gas hydrate, expressed as a unit amount of substance, is J / mol. The amount of heat required to raise the reservoir temperature is determined by the following formula: in, The amount of heat required to heat the reservoir, J; The reservoir skeleton density is expressed in kg / m³. 3 ; is the specific heat capacity of the reservoir framework, J / (kg·K); Let m be the reservoir skeleton volume within the target heating region. 3 ; Density of formation water, kg / m³ 3 ; is the specific heat capacity of formation water, J / (kg·K); Let m be the volume of formation water within the target heating area. 3 ; The initial reservoir temperature is given in °C. Target reservoir temperature, °C; Therefore, the theoretical injection mass of the anhydrous self-generating heat material is determined by the following formula: in, The theoretical injection mass of the anhydrous self-generating heat material, in kg; The heat release per unit mass of the anhydrous self-generating material is expressed in J / kg; when the anhydrous self-generating material is a capsule-type anhydrous self-generating material... The equivalent heat release per unit mass of capsule-type anhydrous self-generating heat material, J / kg; The in-situ heat utilization coefficient is dimensionless. Preferably, the theoretical injection quality is corrected during actual construction: in, The actual injected mass of the anhydrous self-generating heat material is expressed in kg. For the injection correction coefficient, dimensionless, and The value ranges from 1.2 to 1.5; In step S6, the low-water-content carrier liquid is used to suspend, disperse, and transport the anhydrous self-generating heat material; The coating layer of the capsule-shaped anhydrous self-generating heat material gradually opens under the infiltration of reservoir water, swelling upon contact with water, compression of fracture walls, or shearing action of pore throats, exposing the core material and allowing it to contact reservoir water, residual fracturing fluid, or decomposition water of natural gas hydrates to release heat. The released heat is transferred to the surrounding natural gas hydrate reservoir through the artificial fracture walls and reservoir pores, increasing the reservoir temperature, replenishing the heat required for the decomposition of natural gas hydrates, and promoting the continued decomposition of natural gas hydrates into natural gas and water.

10. The method for efficient combined production of deep-water shallow gas and natural gas hydrates according to claim 9, characterized in that, In step S8, to ensure that the pressure reduction sweep area of ​​the surrounding production wells overlaps with the fracture network and the heat release area of ​​the anhydrous self-generating heat material formed by the central well, the well distance between the production wells and the central well is determined based on the reservoir pressure diffusion characteristics. The pressure reduction sweep radius of the production wells is determined using the following relationship: in, For production wells during production time The radius of the voltage drop wave, in meters; m is the reservoir permeability. 2 ; Reservoir porosity, dimensionless; The viscosity of the fluid is Pa·s; The overall compression factor is Pa⁻¹; This is a pressure wave correction factor, dimensionless; Well spacing between production wells and center wells satisfy: in, Let be the distance between the production well and the central well, in meters; The effective heating radius, in meters, is formed around the central well by the anhydrous self-generating heat material.

Images