Natural gas hydrate reservoir in-situ fluid sampling device and method

Abstract

The invention discloses a natural gas hydrate reservoir in-situ fluid sampling device and method, and relates to the technical field of natural gas exploitation. The pumping module is used as a driving device for pumping formation fluid; the double-packer module comprises an upper packer and a lower packer, a sealed test interval is formed between the upper packer and the lower packer, and a pipeline connected with the pumping module penetrates through the upper packer to reach the test interval and is connected with a probe; the probe is used for penetrating out of a test interval to extract formation fluid; a lower packer, an upper packer and a pumping module are sequentially arranged from bottom to top from the bottom of the well; the in-situ fluid identification and sampling module comprises a PVT sampling barrel and a resistivity sensor; and the PVT sampling barrel and the resistivity sensor are connected to the pipeline between the upper packer and the pumping module and penetrate through the wall of the pipeline so as to measure the formation fluid extracted from the pipeline. The in-situ fluid under the original condition can be collected.

Description

Technical Field

[0001] This application relates to the field of natural gas extraction technology, and in particular to an in-situ fluid sampling device and method for natural gas hydrate reservoirs. Background Technology

[0002] Natural gas hydrate reservoirs, especially silty-muddy reservoirs, are characterized by shallow burial depth, unconsolidation, low strength, and susceptibility to disturbance. These characteristics pose significant challenges to traditional core drilling techniques: during the process of raising the core from the well bottom to the sea surface, the temperature and pressure environment changes drastically, causing the natural gas hydrates contained in the sediment pores to decompose, and the sedimentary skeleton to expand or deform due to stress release. Therefore, even with the most advanced pressure-holding core drilling techniques, the reservoir geological parameters, especially fluid parameters, obtained from testing these cores in the laboratory cannot fully represent the true situation under the original formation conditions. This leads to significant uncertainties in natural gas hydrate accumulation simulation, dynamic evolution studies, and development effect predictions based on these parameters. Summary of the Invention

[0003] The main objective of this application is to provide an in-situ fluid sampling device and method for natural gas hydrate reservoirs to obtain in-situ fluid under original conditions.

[0004] To achieve the above objectives, one aspect of this application provides an in-situ fluid sampling device for natural gas hydrate reservoirs, the sampling device comprising: a power module, a pumping module, a dual packer module, a probe, and an in-situ fluid identification and sampling module; The power module is used to supply power. The pump module serves as a driving device for extracting formation fluids. The dual packer module includes an upper packer and a lower packer, forming a sealed test zone between the upper packer and the lower packer. The pipe connected to the pump module passes through the upper packer to reach the test zone and is connected to the probe. The probe is used to penetrate the test area and then extract formation fluid; The lower packer, the upper packer, and the pumping module are installed sequentially from bottom to top at the bottom of the well. The in-situ fluid identification and sampling module includes a PVT sampling bucket and a resistivity sensor; The PVT sampling bucket and the resistivity sensor are connected to the pipeline between the upper packer and the pumping module, and penetrate the pipeline wall to measure the formation fluid extracted from the pipeline.

[0005] In some embodiments, both the upper packer and the lower packer include a central tube made of metal and are externally fitted with multiple sets of special rubber sealing cups; The internal hydraulic systems of the upper packer and the lower packer are used to push the piston outward in response to the setting command, causing the multiple sets of special rubber sealing cups to expand outward in stages.

[0006] In some embodiments, the probe is made of glass copper or titanium alloy material; The probe is cylindrical with a conical or needle-like tip at the front end; The probe has a fluid channel inside and is connected to the pipe.

[0007] In some embodiments, the PVT sampling container is a pressure-resistant container with a high-pressure valve, and the PVT sampling container is pre-filled with inert gas. The resistivity sensor is used to detect the resistivity of the fluid in the pipe. When the target resistivity is detected, the fluid in the pipe is determined to be the target fluid. The PVT sampling tank is used to open the corresponding valve in response to the collection command, so as to collect the target fluid into the tank.

[0008] In some embodiments, the sampling device further includes a temperature sensor and a first pressure sensor; The temperature sensor and the first pressure sensor are located within the test range.

[0009] In some embodiments, the sampling device further includes a second pressure sensor; The second pressure sensor is located in the lower section of the lower packer.

[0010] In some embodiments, the sampling device further includes a density sensor; The density sensor is connected to the pipe between the upper packer and the pumping module and penetrates the pipe wall to measure the density of the formation fluid pumped out of the pipe.

[0011] In some embodiments, the sampling device further includes a controller; The controller is used to power the sampling device via a cable and dynamically receive data collected by each sensor in the sampling device.

[0012] In some embodiments, the sampling device further includes an interactive terminal; The interactive terminal is used to display, analyze, store, or replay data collected by various sensors in the sampling device; and to control the PVT sampling bucket to perform sampling in response to the operator's instructions.

[0013] To achieve the above objectives, another aspect of this application proposes a control method for an in-situ fluid sampling device for a natural gas hydrate reservoir, applied to the aforementioned in-situ fluid sampling device for a natural gas hydrate reservoir. The control method includes the following steps: The upper and lower packers in the sampling device are controlled to set and seal, so as to form a sealed test area; The pump module is activated to extract formation fluids via probes. The target fluid is identified and sampled using the in-situ fluid identification and sampling module.

[0014] The embodiments of this application include at least the following beneficial effects: This application provides an in-situ fluid sampling device and method for natural gas hydrate reservoirs. The sampling device includes: a power supply module, a pumping module, a dual packer module, a probe, and an in-situ fluid identification and sampling module. The power supply module provides power. The pumping module serves as a driving device for extracting formation fluid. The dual packer module includes an upper packer and a lower packer, forming a sealed test area between them. A pipe connected to the pumping module passes through the upper packer to reach the test area and connects to the probe. The probe is used to penetrate the test area and extract formation fluid. The lower packer, upper packer, and pumping module are sequentially arranged from bottom to top. The in-situ fluid identification and sampling module includes a PVT sampling bucket and a resistivity sensor. The PVT sampling bucket and resistivity sensor are connected to the pipe between the upper packer and the pumping module, and penetrate the pipe wall to measure the formation fluid extracted within the pipe. This application achieves a sealed test zone through a dual packer module, which can determine in-situ environmental parameters, extract formation fluids using probes, and then analyze and sample the formation fluids through an in-situ fluid identification and sampling module. This allows for the collection of in-situ fluids under original conditions, providing a raw and authentic data foundation for natural gas reservoir research. Attached Figure Description

[0015] To more clearly illustrate the technical solutions in the embodiments of this application, the accompanying drawings used in the description of the embodiments will be briefly introduced below. Obviously, the accompanying drawings described below are only some embodiments of this application. For those skilled in the art, other drawings can be obtained based on these drawings without creative effort.

[0016] Figure 1 A schematic diagram of the structure of an in-situ fluid sampling device for a natural gas hydrate reservoir provided in this application embodiment; Figure 2 An example flowchart of a control method for an in-situ fluid sampling device for a natural gas hydrate reservoir provided in this application embodiment. Detailed Implementation

[0017] To make the objectives, technical solutions, and advantages of this application clearer, the following detailed description is provided in conjunction with the accompanying drawings and embodiments. It should be understood that the specific embodiments described herein are merely illustrative of this application and are not intended to limit it. In the following description, when referring to the accompanying drawings, unless otherwise indicated, the same numbers in different drawings represent the same or similar elements. The embodiments described in the following exemplary embodiments do not represent all embodiments consistent with those of this application; they are merely examples of apparatuses and methods consistent with some aspects of the embodiments of this application as detailed in the appended claims.

[0018] Unless otherwise defined, all technical and scientific terms used herein have the same meaning as commonly understood by one of ordinary skill in the art to which this application belongs. The terminology used herein is for the purpose of describing embodiments of this application only and is not intended to limit this application.

[0019] Before providing a detailed description of the embodiments of this application, some related technologies involved in the embodiments of this application will be described first, as follows: Terminology Explanation: Natural gas hydrates are cage-like crystalline compounds formed by the combination of natural gas molecules and water molecules in the low-temperature (0-10℃) and high-pressure environment of the deep ocean. They are mostly stored in the pores of seabed sediments and are an important new type of clean energy.

[0020] In-situ formation testing: refers to the technique of directly lowering testing instruments into the bottom of the well to measure parameters and sample fluids under the original temperature, pressure and stress environment of the reservoir. It aims to minimize disturbance and changes in physical properties during sample collection and transportation.

[0021] Dual packers: Employing a two- or multi-stage sealing structure, they can be set in unconsolidated formations, thereby forming an isolated test chamber between the instrument and the wellbore, ensuring effective isolation between the test area and other parts of the wellbore. They are a key component for obtaining accurate in-situ data.

[0022] PVT sample container: A specialized pressure-maintaining sampling container capable of maintaining the original pressure (P), volume (V), and temperature (T) of formation fluids during sampling. This device enables accurate sampling of gas-water-hydrate multiphase fluids in hydrate systems, effectively preventing phase changes and component loss. Cable-guided formation testing: This is a dynamic testing technique that uses a cable to deliver testing instruments to the target reservoir, isolates the formation with probes or packers, extracts fluids and records pressure curves, collects samples, and quickly obtains parameters such as reservoir pressure and fluid properties for preliminary reservoir evaluation.

[0023] BSR (Bottom-of-the-Sea Reflector): A strong reflective interface parallel to the seabed, which appears in marine seismic exploration. It is usually considered to be the bottom boundary of the gas hydrate stability zone and is a key geophysical anomaly guiding the site selection for gas hydrate drilling.

[0024] In-situ pore fluid: Fluids filling the pores of sediments under the original temperature and pressure conditions of the natural gas hydrate reservoir, unaffected by natural gas hydrate decomposition or sampling disturbance. This includes the original pore water chemical composition and salinity information (e.g., Cl-) before natural gas hydrate decomposition. - Concentration can directly indicate the paleoenvironmental conditions during the formation of natural gas hydrates and is a key basis for inverting the hydrocarbon accumulation process.

[0025] Miniature drill pipe test: A simplified version of traditional drill pipe test (DST). It uses modular equipment to seal short well sections, quickly complete pressure testing and fluid sampling, and obtain reservoir permeability and other data at low cost and high efficiency. It is suitable for scenarios where conventional oil testing is difficult.

[0026] Formation pressure: refers to the pressure exerted on fluids within the pores of underground rock, also known as pore pressure. It is one of the key parameters for determining whether natural gas hydrates are in a stable state under current temperature and pressure conditions.

[0027] Chloride ion desalination: This refers to the decomposition of natural gas hydrates during sampling due to pressure release, releasing fresh water from the crystal lattice and diluting ions (especially Cl-) in the original pore water. - This results in measured salinity being lower than the in-situ true value. This effect makes the obtained pore water unable to represent the original geochemical characteristics of the formation fluids, thus limiting the accuracy of hydrate accumulation history reconstruction and resource assessment.

[0028] To overcome the inherent limitations of core laboratory testing, downhole in-situ testing technology is widely recognized as the most promising solution. This technology lowers the measuring device directly to the reservoir location, performing real-time measurements and fluid acquisition under pristine temperature and pressure conditions, fundamentally avoiding disturbance issues during core extraction. Internationally, oilfield service companies such as Schlumberger and Baker Hughes have commercially applied wireline formation testers (such as MDT and RCI) in conventional oil and gas sandstone reservoirs, leading to the development of Mini-DST (mini-drill pipe formation testing) technology for specific needs. The basic principle of this type of technology is to isolate a well section by setting a packer and then using a downhole pump to extract a small amount of formation fluid at a controlled rate. However, these technologies, developed based on conventional oil and gas reservoirs, exhibit significant inadequacies when directly applied to unconsolidated natural gas hydrate reservoirs. First, their packer designs, primarily designed for hard rock wellbore walls, struggle to achieve effective seals in loose, volatile silty mudstone formations, leading to a high risk of setting failure or seal failure during testing. Second, the pumping modules of conventional tools are often designed for high-permeability sandstone, and their flow rate and pressure drop control modes may be too harsh for low-permeability, easily damaging natural gas hydrate reservoirs, potentially causing fine particle transport that clogs flow channels or damages the reservoir structure. Furthermore, the fluid analysis modules of existing tools focus more on oil and gas identification, paying insufficient attention to in-situ pore water chemical analysis, crucial for natural gas hydrate reservoir research, and the fidelity of the sampling process needs improvement. Finally, the complex system structure and operational procedures of these mature tools result in high operating costs, significantly limiting the large-scale application of this technology in natural gas hydrate exploration.

[0029] CN201910382717.X discloses a numerical simulation method for pumping in cable formation testing and a numerical correction method for the process, including the following steps: S1, determining the flow pattern of the pressure measurement data from cable formation testing and obtaining the corresponding flow rate; S2, the probe opens a test hole on the wellbore, the intrusion zone and formation fluid begin to flow into the wellbore, the sampler extracts the formation fluid, the formation fluid flows instantaneously and forms a flow pattern and continuous conduction, generating a sweep range, and an ellipsoid is used to simulate the sweep range formed by the continuous conduction of formation fluid flow; S3, based on given reservoir physical parameters and intrusion depth, the pre-test predicted pumping breakthrough time, pumping time, and corresponding volume are obtained according to the algorithm; S4, the pumping breakthrough time and volume are picked up from the monitoring parameters of cable formation testing pumping, and the pumping results are corrected by optimizing the algorithm fitting function and simulation calculation, so as to obtain the actual effect of pumping in a timely manner, guide engineering operations, and improve operational efficiency.

[0030] CN110043254A discloses a method for obtaining effective formation permeability based on cable formation testing data, including the following steps: S1, analyzing cable formation testing pressure recovery data and calculating radial flow mobility M; S2, establishing a relationship model between the radial flow mobility M obtained from cable formation testing data and the porosity curve Φ, clay content V, and reservoir thickness H from conventional well logging results, and calculating the static radial flow mobility M using the well logging curve; S3, calibrating the static mobility curve M with the mobility from cable formation testing to obtain an effectively corrected mobility curve M; S4, performing a scale conversion between the dynamic mobility curve M and the mobility from DST testing to obtain the effective permeability and formation coefficient of the reservoir, which facilitates better analysis of reservoir productivity.

[0031] CN202010617439.4 discloses a "Test Apparatus and Method for Natural Gas Hydrate Formation under Simulated Flow Conditions." This invention relates to a test apparatus and method for natural gas hydrate formation under simulated flow conditions, comprising: a circulating circular pipe with an inlet, an outlet, and a natural gas hydrate circulation sampling device. The natural gas hydrate circulation sampling device drives the mixed fluid within the circulating circular pipe to circulate, simultaneously collecting data such as temperature, pressure, and phase content. The output ports of a natural gas supply device, a water supply device, and a refrigeration device are all connected to the interior of the circulating circular pipe via inlets, respectively providing the circulating circular pipe with pre-pressurized natural gas, water, and cold water. The inlet of a multiphase separation device is connected to the interior of the circulating circular pipe via an outlet, used for multiphase separation of the multiphase mixed fluid discharged from the circulating circular pipe after the experiment. A video monitoring device is used for video data acquisition. A computer control device is used for unified control of all devices. This invention can be widely applied in the field of natural gas hydrate extraction.

[0032] CN201810751552.4 discloses a "method for calculating water saturation in the flushed zone of a porous reservoir based on dielectric experiments". This method involves calculating water saturation in the flushed zone of a porous reservoir based on dielectric experiments, including: S1 Core preparation: Selecting six core samples with different porosities and permeabilities, and pre-treating the cores by washing and drying; S2 Dielectric parameter acquisition: Using an electromagnetic parameter analyzer, conducting experimental analysis on multiple core samples at a frequency of 984MHz to obtain the dielectric parameters of each core under different water saturation conditions; S3 Porosity parameter measurement: Measuring the porosity parameters of multiple cores using a porosity analyzer; S4 Experimental data analysis: Analyzing the dielectric experimental data of the cores; S5 Formation parameter acquisition: Acquiring and recording formation dielectric parameter data and formation porosity parameters using a dielectric and porosity logging device; S6 Formula calculation: Obtaining the results according to the formula; S7 Result output: Outputting the calculation results. It can be widely used in the field of evaluating the water saturation of flushed zones in formations with complex pore structures.

[0033] In summary, the industry currently lacks a comprehensive downhole testing equipment specifically designed for the geological and engineering characteristics of shallow unconsolidated natural gas hydrate reservoirs, capable of reliable isolation, low-disturbance testing, high-fidelity sampling, and cost-effectiveness.

[0034] Based on the analysis of existing technologies, especially commercial cable-based formation testing tools and related patent literature, the following main drawbacks can be identified when applying them to natural gas hydrate reservoirs: (1) Insufficient formation adaptability: Existing tool sealing systems are difficult to form a durable and reliable seal in unconsolidated, easily enlarged silty mudstone formations, and micro-leakage during the testing process will seriously interfere with the authenticity of the data. (2) The testing process may cause significant damage to the reservoir: The design of conventional pumping modules does not fully consider the low permeability and structural fragility of natural gas hydrate reservoirs. Excessive pumping rate or excessive pressure drop may cause the migration and rearrangement of sediment particles in the near-wellbore zone, or even induce microfractures, which may change the original seepage characteristics and fluid geochemical properties of the area under test, and the measured parameters may no longer be "in-situ".

[0035] (3) The fluid sampling and analysis functions are not targeted enough: Existing fluid identification technologies (such as those based on optics or single resistivity) mainly serve oil and gas exploration and are not sensitive to the most critical phase changes (formation / decomposition of natural gas hydrates) and in-situ pore water chemical characteristics in natural gas hydrate systems. The pressure and temperature control precision during the sampling process is insufficient to completely maintain the original state of the fluid in the natural gas hydrate layer, affecting the accuracy of subsequent fluid geochemical analysis.

[0036] (4) Poor system integration and operational economy: Mature commercial tools are complex and dependent on imports, resulting in extremely high costs per operation, making it difficult to meet the actual needs of my country's natural gas hydrate detailed exploration and evaluation stage, which requires a large amount of data acquisition while controlling costs. At the same time, their operation process is complex and has high requirements for operators and ship equipment, which is not conducive to the rapid promotion and routine application of the technology.

[0037] To address the aforementioned technical deficiencies, the purpose of this application is to provide a downhole in-situ testing and sampling device and method specifically designed for shallow unconsolidated natural gas hydrate reservoirs. The objective of this sampling device is: (1) Achieve reliable isolation: Innovatively design a dual packer module that can adapt to the unconsolidated formation wellbore and has multi-level sealing capabilities, ensuring effective isolation between the test chamber and the upper wellbore throughout the entire test cycle, laying the foundation for obtaining the real formation pressure response.

[0038] (2) Low-disturbance pumping system: It integrates a high-precision pumping unit that is precisely adapted to the reservoir characteristics, and is equipped with a fast-response pressure and temperature sensing system. It can achieve micro-flow and low-disturbance pumping of formation fluids, and accurately capture in-situ pressure, temperature and key parameters of reservoir fluids. Combined with the hydrate decomposition kinetic model, it can accurately predict the stable temperature and pressure threshold of hydrate reservoir section, and thus achieve dynamic and precise control of depressurization strategy and pumping parameters.

[0039] (3) Obtaining high-fidelity fluid samples: Using multi-channel PVT pressure-holding sampling technology and combined with fluid identification methods that integrate multiple sensors such as resistivity and acoustic waves, in-situ pore fluid samples representing the original conditions of the formation can be obtained while accurately judging the properties of the fluid (such as distinguishing between free gas and formation water).

[0040] (4) Form a standardized and efficient operation process: integrate the functional modules to form a set of tools with a compact structure and standardized operation, and provide clear full-process operation guidelines to improve the success rate of operations and data quality, while reducing the dependence on high-end operation vessels, thereby improving the economy and applicability of the technology.

[0041] Ultimately, the embodiments of this application aim to provide a sampling device for natural gas hydrate resource exploration that can accurately obtain in-situ reservoir fluid pore water parameters, providing direct data support for reservoir formation mechanism research, resource reserve evaluation, and safe and efficient development.

[0042] This application provides an in-situ fluid sampling device for natural gas hydrate reservoirs. The sampling device includes: a power module, a pumping module, a dual packer module, a probe, and an in-situ fluid identification and sampling module. The power module is used to supply power. The pump module serves as a driving device for extracting formation fluids. The dual packer module includes an upper packer and a lower packer, forming a sealed test zone between the upper packer and the lower packer. The pipe connected to the pump module passes through the upper packer to reach the test zone and is connected to the probe. The probe is used to penetrate the test area and then extract formation fluid; The lower packer, the upper packer, and the pumping module are installed sequentially from bottom to top at the bottom of the well. The in-situ fluid identification and sampling module includes a PVT sampling bucket and a resistivity sensor; The PVT sampling bucket and the resistivity sensor are connected to the pipeline between the upper packer and the pumping module, and penetrate the pipeline wall to measure the formation fluid extracted from the pipeline.

[0043] Specifically, this application integrates power supply, pumping, dual containment, monitoring, identification, sampling, and control modules into a compact tool string that can be transported via standard drill pipe. This highly integrated design is a core innovation aimed at reducing operational complexity and cost in natural gas hydrate exploration.

[0044] Optionally, both the upper packer and the lower packer include a central tube made of metal and are externally fitted with multiple sets of special rubber sealing cups; The internal hydraulic systems of the upper packer and the lower packer are used to push the piston outward in response to the setting command, causing the multiple sets of special rubber sealing cups to expand outward in stages.

[0045] Specifically, the dual packer module includes a multi-stage hydraulic drive, a composite sealing sleeve structure with a "central convex" deformation characteristic, and a coordinated action mechanism between the upper and lower packers and the central injection probe. This design ensures the ability to form a stable and reliable test chamber in loose, irregular wellbores.

[0046] Optionally, the probe is made of glass copper or titanium alloy. The probe is cylindrical with a conical or needle-like tip at the front end; The probe has a fluid channel inside and is connected to the pipe.

[0047] Specifically, the probe body is precision-machined from glassy copper (Glidcop) or titanium alloy. Both materials possess high strength, high toughness, excellent resistance to seawater corrosion, and are non-magnetic, making them ideal for deep-sea unconsolidated formation environments. The probe is designed as a slender cylinder with a tapered or needle-like tip to facilitate penetration into soft sediments. An internal fluid channel connects to the test module at the rear. The probe's extension and retraction are controlled by an independent micro-hydraulic cylinder, extending only after the packer has set to minimize disturbance to the wellbore. The probe's outer diameter is carefully designed to ensure sufficient structural strength to resist formation resistance while allowing smooth passage within the standard drill pipe diameter; its typical outer diameter range is 10–15 mm.

[0048] Optionally, the PVT sampling container is a pressure-resistant container with a high-pressure valve, and the inside of the PVT sampling container is pre-filled with inert gas; The resistivity sensor is used to detect the resistivity of the fluid in the pipe. When the target resistivity is detected, the fluid in the pipe is determined to be the target fluid. The PVT sampling tank is used to open the corresponding valve in response to the collection command, so as to collect the target fluid into the tank.

[0049] Specifically, the in-situ fluid identification and sampling module includes one or more PVT (Pressure-Volume-Temperature) sampling tanks and resistivity sensors. The PVT sampling tank is a pressure-resistant container with a high-pressure valve, pre-filled with an inert gas (such as nitrogen) to maintain pressure. After pressure measurement, to obtain pure formation fluid, a miniature electric pump is activated for low-volume extraction to replace residual drilling fluid in the test area. During this process, the fluid flowing through the pipeline passes through the resistivity sensor. Because the resistivity of water (especially saline pore water) is much lower than that of gas, by monitoring changes in resistivity in real time, operators can clearly determine whether water or gas is being extracted. Once the target fluid (such as pore water) is confirmed to have been extracted, the corresponding PVT tank valve can be remotely opened to collect the fluid. The special structure of the PVT tank ensures that the sample maintains its original temperature and pressure state throughout the entire process from collection to delivery to the laboratory for analysis, guaranteeing sample fidelity.

[0050] Optionally, the sampling device further includes a temperature sensor and a first pressure sensor; The temperature sensor and the first pressure sensor are located within the test range.

[0051] Optionally, the sampling device further includes a second pressure sensor; The second pressure sensor is located in the lower section of the lower packer.

[0052] Optionally, the sampling device further includes a density sensor; The density sensor is connected to the pipe between the upper packer and the pumping module and penetrates the pipe wall to measure the density of the formation fluid pumped out of the pipe.

[0053] Optionally, the sampling device further includes a controller; The controller is used to power the sampling device via a cable and dynamically receive data collected by each sensor in the sampling device.

[0054] Specifically, the controller is responsible for issuing commands, acquiring data, real-time monitoring, data processing, and storage. It supplies power to the downhole equipment via cable and receives data signals in real time from sensors such as pressure and resistivity sensors. Data transmission employs a highly interference-resistant digital communication protocol to ensure data integrity during long-distance transmission in the deep sea.

[0055] Optionally, the sampling device further includes an interactive terminal; The interactive terminal is used to display, analyze, store, or replay data collected by various sensors in the sampling device; and to control the PVT sampling bucket to perform sampling in response to the operator's instructions.

[0056] Specifically, the software interface can display various sensor data curves in real time (such as pressure-time curves and resistivity-time curves). The software has real-time data storage, playback, and preliminary analysis functions. Operators can accurately determine the moment of pore water appearance based on the abrupt change points of the resistivity curve and remotely command the PVT sample tank to take samples. All raw data and operation logs are securely stored for subsequent offline analysis.

[0057] The following sections will provide a detailed description and explanation of some optional embodiments of this application, using specific application examples.

[0058] The core of this application's embodiments lies in providing an integrated downhole testing equipment capable of stable and reliable operation in the harsh environment of the deep sea. The following will combine... Figure 1 The paper elaborates on the various components of the sampling device and their collaborative working methods.

[0059] The overall design of this sampling device follows the principles of modularity, pressure resistance, and high reliability. The main structure of the tool string is made of high-strength glassy copper (beryllium bronze) or TC4 titanium alloy. These two materials possess excellent mechanical strength, good resistance to seawater corrosion, and non-magnetic properties, avoiding interference with magnetic positioning and other measurement signals during geophysical logging. All external connections use API standard drill pipe threads or dedicated quick-connect electrical and hydraulic cables to ensure smooth and airtight operation during the lowering of the drill pipe (104.8mm diameter). The tool string is designed for a water depth of at least 1000 meters (withstanding external hydrostatic pressure ≥10MPa), and is suitable for reservoir temperatures ranging from 0-50℃. Its overall pressure resistance has been tested using finite element analysis and pressure cylinder testing to ensure safe operation under rated conditions.

[0060] (a) Power module.

[0061] The power module is responsible for providing energy output to the entire downhole equipment, and its stability directly determines the duration and data quality of operations. This module abandons the traditional disposable battery solution and adopts a rechargeable lithium-ion battery pack. The battery pack consists of multiple individual cells connected in parallel and then in series to achieve the required voltage (typically 48VDC) and capacity (≥5kWh). The module integrates a sophisticated battery management system (BMS), which monitors the voltage, charging and discharging current of each cell, and the internal temperature of the module in real time, providing overvoltage, undervoltage, overcurrent, short circuit, and overtemperature protection. All battery status data is uploaded to the ground control system in real time via cable, allowing operators to monitor remaining power and battery health at any time. The module shell is a fully sealed welded structure, filled with thermally conductive silicone, ensuring structural integrity under 70MPa high pressure and facilitating uniform heat dissipation during battery operation.

[0062] (ii) Pumping module.

[0063] The pump module is the driving device for realizing the flow and pressure disturbance of formation fluids. To adapt to the low permeability and vulnerability of natural gas hydrate reservoirs, this module uses a miniature plunger pump driven by a brushless DC motor. This pump type features high output pressure (up to 20 MPa or more), precise flow control, and low pulse frequency. The pump's stroke frequency can be precisely set via commands sent from the ground control system. Multi-layer sintered metal filters with a filtration accuracy of 10 microns are installed at both the pump inlet and outlet, effectively preventing silt particles from entering the pump body and preventing wear and jamming. The entire pump module is mounted on a vibration-damping bracket to reduce mechanical vibration interference to other precision sensors within the tool string.

[0064] (iii) Dual packer module.

[0065] This module contains a pair of packers (upper and lower) forming a closed test zone. At the core of each packer is a central tube made of high-strength metal, externally fitted with multiple sets of special rubber sealing elements. During setting, the surface control system activates the internal hydraulic system, pushing the piston outward and forcing the sealing elements to expand outward in stages, like an accordion. This multi-stage sealing design ensures a continuous and reliable seal even in cases of localized wellbore irregularities or slight enlargement, effectively preventing leakage of the test fluid along the wellbore and ensuring the accuracy of pressure testing and fluid sampling. The setting force of the packers is precisely controlled by the internal hydraulic system, guaranteeing sufficient sealing force without damaging the soft formation structure due to excessive pressure.

[0066] (iv) Probe module.

[0067] The probe body is precision-machined from glassy copper (Glidcop) or titanium alloy. Both materials possess high strength, high toughness, excellent resistance to seawater corrosion, and are non-magnetic, making them ideal for deep-sea unconsolidated formation environments. The probe is designed as a slender cylinder with a tapered or needle-like tip to facilitate penetration into soft sediments. An internal fluid channel connects to the test module at the rear. The probe's extension and retraction are controlled by an independent micro-hydraulic cylinder, extending only after the packer has set to minimize disturbance to the wellbore. The probe's outer diameter is carefully designed to ensure sufficient structural strength to resist formation resistance while allowing smooth passage within the standard drill pipe diameter; its typical outer diameter range is 10–15 mm.

[0068] (v) In-situ fluid identification and sampling module.

[0069] This module comprises one or more PVT (Pressure-Volume-Temperature) sampling tanks and a resistivity sensor. The PVT sampling tank is a pressure-resistant container with a high-pressure valve, pre-filled with an inert gas (such as nitrogen) to maintain pressure. After pressure measurement, a miniature electric pump is activated to extract pure formation fluid at a low flow rate, displacing any residual drilling fluid in the test area. During this process, the fluid flowing through the pipeline passes through the resistivity sensor. Because the resistivity of water (especially saline pore water) is much lower than that of gas, by monitoring changes in resistivity in real time, operators can clearly determine whether water or gas is being extracted. Once the target fluid (such as pore water) is confirmed, the corresponding PVT tank valve can be remotely opened to collect the fluid. The special structure of the PVT tank ensures that the sample maintains its original temperature and pressure conditions throughout the entire process from collection to delivery to the laboratory for analysis, guaranteeing sample fidelity. The number of sampling buckets can be configured according to task requirements, with a typical configuration of 2–4 buckets to meet the segmented sampling needs of different fluid stages (such as initial contaminated liquid, transition section, and pure pore water).

[0070] (vi) Data acquisition, processing and analysis module.

[0071] This module is responsible for the entire system's command issuance, data acquisition, real-time monitoring, data processing, and storage, and mainly consists of two parts: hardware and software. Hardware components: Consisting of a data acquisition controller installed in the surface control room and a dedicated cable connecting to the downhole equipment. The controller supplies power to the downhole equipment via the cable and receives data signals in real time from sensors such as pressure and resistivity sensors. Data transmission employs a highly interference-resistant digital communication protocol to ensure data integrity during long-distance transmission in the deep sea.

[0072] Software component: Dedicated data acquisition and processing software has been developed to support the software. The software interface can display various sensor data curves in real time (such as pressure-time curves and resistivity-time curves). The software has real-time data storage, playback, and preliminary analysis functions. Operators can accurately determine the moment of pore water appearance based on the abrupt change points of the resistivity curve and remotely command the PVT sample tank to start sampling. All raw data and operation logs are securely stored for subsequent offline analysis.

[0073] This application targets shallow, unconsolidated natural gas hydrate reservoirs, aiming to solve the key challenge of obtaining high-fidelity in-situ fluid samples and formation pore water parameters using existing technologies. Traditional core sampling, during the process of lifting to the surface, inevitably leads to the decomposition of natural gas hydrates and disturbance of sediment structures due to pressure release and temperature changes, resulting in significant deviations between laboratory test data and the actual formation conditions. This sampling device overcomes this bottleneck by integrating modular design and downhole in-situ operations, directly placing the in-situ sampling process within the target reservoir environment. This sampling device integrates key technologies such as efficient pressure isolation, low-disturbance fluid pumping, multi-sensor real-time monitoring, and PVT fluid preservation, constructing a complete operational system capable of in-situ fluid sampling and analysis in deep-sea natural gas hydrate reservoirs. The direct application of this sampling device will provide accurate geological data support for research on the dynamic accumulation mechanism of natural gas hydrates, precise assessment of resource potential, and optimization of development plans.

[0074] To achieve the above objectives, another aspect of this application proposes a control method for an in-situ fluid sampling device for a natural gas hydrate reservoir, applied to the aforementioned in-situ fluid sampling device for a natural gas hydrate reservoir. The control method includes the following steps: The upper and lower packers in the sampling device are controlled to set and seal, so as to form a sealed test area; The pump module is activated to extract formation fluids via probes. The target fluid is identified and sampled using the in-situ fluid identification and sampling module.

[0075] Specifically, refer to Figure 2 A complete downhole in-situ testing operation involves the following detailed steps: 1. Tool String Assembly and Ground Testing: Before operation, connect all functional modules sequentially on the ground and complete the sealing check of all electrical and hydraulic interfaces. Simulate downhole signals using a ground test chamber to conduct comprehensive functional tests on the power supply, pumps, valves, sensors, and data transmission system to ensure the tool string is in normal working order.

[0076] 2. Tool String Lowering and Positioning: The assembled and tested tool string is connected to the bottom of the drill pipe and slowly lowered to the target reservoir depth determined in advance based on seismic BSR markers, logging curves, and core data. During the lowering process, the readings of the pressure and temperature sensors inside the tool string are monitored in real time to assist in depth correction and precise positioning of the reservoir top and bottom interfaces.

[0077] 3. Dual Packer Setting and Test Chamber Establishment: After reaching the target depth, drill string activity is stopped. The hydraulic pump is started by the surface control system to inject hydraulic oil into the dual packer module. The setting pressure curve is monitored in real time. When the pressure reaches the preset value and remains stable, it indicates that the upper and lower packer sleeves have fully expanded and formed an effective seal with the well wall. Subsequently, the hydraulic cylinder of the injection probe is controlled to push the probe into the formation, establishing a fluid channel between the test chamber and the formation.

[0078] 4. Pump Initiation and Real-Time Fluid Identification: The in-situ formation pressure is measured using sensor probes and compared with the steady-state pressure of natural gas hydrates calculated from phase equilibrium simulations at that location. This comparison determines the pressure reduction differential, and a pressure reduction strategy is developed based on this differential to lower the reservoir pressure, promoting the decomposition of natural gas hydrates and thus driving the outflow of in-situ pore fluids. At the start of pressure reduction, a low initial pumping rate (e.g., 1 mL / s) is set, and the pumping module is activated to begin extracting fluid from the formation. At this time, the resistivity and acoustic sensors of the fluid identification module begin continuous operation. The resistivity and acoustic attenuation curves are displayed in real-time on the surface monitoring screen. Initially, the extracted fluid is typically drilling fluid filtrate with low resistivity. As the filtrate is gradually drained, and native formation fluids enter the flow channel, the sensor signals undergo characteristic changes (e.g., a significant increase in resistivity may indicate the presence of gas or stabilization at a new level representing formation water). Operators use this real-time information to assess changes in fluid properties. Ground operators manually trigger or the system automatically triggers the designated PVT sample container to complete the sampling process. The system records the precise pressure and temperature at the moment of sampling.

[0079] 5. Packer Unsealing and Tool String Relocation: After completing all testing and sampling tasks at this depth, the control system releases the hydraulic pressure of the packer. The rubber sleeve retracts back to its original position under its own elasticity, and the injection probe is retracted simultaneously. After confirming successful unsealing, the tool string is raised or lowered to the next target testing depth via the drill pipe, and the above steps are repeated. This equipment is designed to support continuous testing of multiple formations in a single downhole operation.

[0080] 6. Tool String Recovery and Data Sample Processing: After completing all predetermined test points, retrieve the tool string to the deck. Carefully disassemble the PVT sample container and immediately connect it to the sample transfer and analysis equipment in the shipboard laboratory for subsequent analysis of fluid composition, ion content, and gas isotopes. Simultaneously, export all downhole data recorded by the surface system for in-depth interpretation using the data processing system.

[0081] Through the standardized operation of the above steps, this embodiment transforms the complex downhole in-situ testing task into an efficient, reliable, and data-quality-controllable industrial process. This equipment and technical process effectively fills a gap in this technological field in China.

[0082] In summary, the embodiments of this application include the following key technical solutions: This application's embodiments represent a systematic and innovative design for a specific application scenario (shallow unconsolidated natural gas hydrate reservoirs), including: 1. Modular Integrated Tool String Structure: This design integrates power supply, pumping, dual containment, monitoring, identification, sampling, and control modules into a compact tool string that can be transported via standard drill pipe. This highly integrated design is a core innovation aimed at reducing operational complexity and costs in natural gas hydrate exploration, while protecting the overall structural layout and the collaborative working relationships between modules.

[0083] 2. Adaptive dual packer system for unconsolidated formations: Specifically, it employs a multi-stage hydraulically driven composite sealing sleeve structure with a "central convex" deformation characteristic, and a coordinated action mechanism between the upper and lower packers and the central injection probe. This design ensures the ability to form stable and reliable test chambers in loose, irregular wellbores.

[0084] 3. Real-time downhole fluid identification method based on multi-sensor information fusion: This method utilizes both resistivity and acoustic intensity sensors to jointly identify pumped fluids. Compared to single-sensor analysis, this multi-parameter fusion analysis method can more effectively and reliably distinguish drilling fluid filtrate, formation water, and free gas, providing crucial information for sampling decisions and test interpretation.

[0085] 4. Low-disturbance, high-fidelity in-situ fluid sampling system: This system relies on calculations of natural gas hydrate formation-decomposition kinetics and measured temperature and pressure data to accurately analyze the equilibrium state of the hydrate stability domain. Through pressure difference comparison, a dynamic control logic is constructed to form a precise depressurization / control process adapted to reservoir characteristics. The system employs multiple independently controlled PVT sample containers, coupled with real-time fluid identification signals to trigger sampling, achieving multi-point pressure-maintaining sampling in a single well run. Leveraging the aforementioned precise pressure control technology and the sample's inherent control logic, the system avoids the risk of hydrate phase transitions, minimizes reservoir disturbance, and ensures high-fidelity capture of in-situ fluid samples, providing reliable basic data for subsequent analysis.

[0086] 5. Standardized operational methods for the entire process of natural gas hydrate reservoirs: This method protects the complete operational flow from tool string deployment, setting, pre-testing, pumping, fluid identification, sampling to desealing and relocation. This process integrates the aforementioned hardware innovations into a set of repeatable and highly efficient operational procedures, representing a key soft power for ensuring the successful application of the technology.

[0087] Beneficial effects: Commercial tools (such as MDTs) are general-purpose equipment with advantages in comprehensive functions and mature models, but their "large and comprehensive" design makes them unsuitable for dealing with the special case of natural gas hydrate reservoirs. Their packers have a low success rate of setting in unconsolidated formations, the pumping system has a high potential for damage to fragile reservoirs, and the overall system operating cost is extremely high.

[0088] This application's embodiment represents a highly specialized and refined design. Its greatest advantage lies in its exceptional geological adaptability. The specially designed dual packer system solves the core challenge of effective sealing in unconsolidated formations, providing a prerequisite for obtaining accurate data. Its low-disturbance testing philosophy is reflected in the small-displacement, precisely controlled pumping system, minimizing damage to the reservoir and ensuring that the measurement results are more representative of the original formation characteristics. High-fidelity sampling capability is achieved through the combination of multiple PVT sample containers and real-time fluid identification technology, ensuring that the obtained fluid samples have higher representativeness and research value. Finally, the high degree of modular integration and process standardization, while ensuring complete functionality, reduces the extreme requirements for operators and equipment, potentially significantly reducing the cost per operation. This makes it possible for this technology to be widely applied in my country's natural gas hydrate exploration practice, reducing dependence on high-end foreign technical services.

[0089] It is understood that the core technical idea of ​​this application's embodiments lies in achieving accurate acquisition of in-situ fluid and pressure parameters of unconsolidated natural gas hydrate reservoirs through a highly integrated, formation-adaptable downhole equipment system. Based on the detailed implementation schemes described above, those skilled in the art can foresee several alternative solutions without departing from the core concept of this invention, and all such solutions should fall within the protection scope of this invention. Specifically, any simple substitution, addition, reduction, or combination of specific implementation components, driving methods, sensor types, or data transmission modes based on the core design idea of ​​this application's embodiments—namely, acquiring in-situ parameters of unconsolidated natural gas hydrate reservoirs through reliable isolation, low-disturbance pumping, multi-sensor identification, and high-fidelity sampling—should fall within the protection scope of this application's embodiments.

[0090] The embodiments described in this application are for the purpose of more clearly illustrating the technical solutions of the embodiments of this application, and do not constitute a limitation on the technical solutions provided by the embodiments of this application. As those skilled in the art will know, with the evolution of technology and the emergence of new application scenarios, the technical solutions provided by the embodiments of this application are also applicable to similar technical problems.

[0091] Those skilled in the art will understand that the technical solutions shown in the figures do not constitute a limitation on the embodiments of this application, and may include more or fewer steps than shown, or combine certain steps, or different steps.

[0092] Those skilled in the art will understand that all or some of the steps in the methods disclosed above, as well as the functional modules / units in the systems and devices, can be implemented as software, firmware, hardware, or suitable combinations thereof.

[0093] The terms “first,” “second,” “third,” “fourth,” etc. (if present) in the specification and accompanying drawings of this application are used to distinguish similar objects and are not necessarily used to describe a specific order or sequence. It should be understood that such data can be interchanged where appropriate so that the embodiments of this application described herein can be implemented in orders other than those illustrated or described herein. Furthermore, the terms “comprising” and “having,” and any variations thereof, are intended to cover non-exclusive inclusion; for example, a process, method, system, product, or apparatus that comprises a series of steps or units is not necessarily limited to those steps or units explicitly listed, but may include other steps or units not explicitly listed or inherent to such processes, methods, products, or apparatus.

[0094] It should be understood that in this application, "at least one (item)" means one or more, and "more than" means two or more. "And / or" is used to describe the relationship between related objects, indicating that three relationships can exist. For example, "A and / or B" can represent three cases: only A exists, only B exists, and both A and B exist simultaneously, where A and B can be singular or plural. The character " / " generally indicates that the preceding and following related objects are in an "or" relationship. "At least one (item) of the following" or similar expressions refer to any combination of these items, including any combination of single or plural items. For example, at least one (item) of a, b, or c can represent: a, b, c, "a and b", "a and c", "b and c", or "a and b and c", where a, b, and c can be single or multiple.

[0095] The preferred embodiments of the present application have been described above with reference to the accompanying drawings, but this does not limit the scope of the claims of the present application. Any modifications, equivalent substitutions, and improvements made by those skilled in the art without departing from the scope and substance of the embodiments of the present application shall be within the scope of the claims of the present application.

Claims

1. An in-situ fluid sampling device for natural gas hydrate reservoirs, characterized in that, The sampling device includes: a power module, a pumping module, a dual packer module, a probe, and an in-situ fluid identification and sampling module; The power module is used to supply power. The pump module serves as a driving device for extracting formation fluids. The dual packer module includes an upper packer and a lower packer, forming a sealed test zone between the upper packer and the lower packer. The pipe connected to the pump module passes through the upper packer to reach the test zone and is connected to the probe. The probe is used to penetrate the test area and then extract formation fluid; The lower packer, the upper packer, and the pumping module are installed sequentially from bottom to top at the bottom of the well. The in-situ fluid identification and sampling module includes a PVT sampling bucket and a resistivity sensor; The PVT sampling bucket and the resistivity sensor are connected to the pipeline between the upper packer and the pumping module, and penetrate the pipeline wall to measure the formation fluid extracted from the pipeline.

2. The in-situ fluid sampling device for natural gas hydrate reservoirs according to claim 1, characterized in that, Both the upper packer and the lower packer include a central tube made of metal and are externally fitted with multiple sets of special rubber sealing cups; The internal hydraulic systems of the upper packer and the lower packer are used to push the piston outward in response to the setting command, causing the multiple sets of special rubber sealing cups to expand outward in stages.

3. The in-situ fluid sampling device for natural gas hydrate reservoirs according to claim 1, characterized in that, The probe is made of glass copper or titanium alloy material; The probe is cylindrical with a conical or needle-like tip at the front end; The probe has a fluid channel inside and is connected to the pipe.

4. The in-situ fluid sampling device for natural gas hydrate reservoirs according to claim 1, characterized in that, The PVT sampling container is a pressure-resistant container with a high-pressure valve, and the inside of the PVT sampling container is pre-filled with inert gas. The resistivity sensor is used to detect the resistivity of the fluid in the pipe. When the target resistivity is detected, the fluid in the pipe is determined to be the target fluid. The PVT sampling tank is used to open the corresponding valve in response to the collection command, so as to collect the target fluid into the tank.

5. The in-situ fluid sampling device for natural gas hydrate reservoirs according to claim 1, characterized in that, The sampling device also includes a temperature sensor and a first pressure sensor; The temperature sensor and the first pressure sensor are located within the test range.

6. The in-situ fluid sampling device for natural gas hydrate reservoirs according to claim 1, characterized in that, The sampling device also includes a second pressure sensor; The second pressure sensor is located in the lower section of the lower packer.

7. The in-situ fluid sampling device for natural gas hydrate reservoirs according to claim 1, characterized in that, The sampling device also includes a density sensor; The density sensor is connected to the pipe between the upper packer and the pumping module and penetrates the pipe wall to measure the density of the formation fluid pumped out of the pipe.

8. A natural gas hydrate reservoir in-situ fluid sampling device according to any one of claims 1 to 7, characterized in that, The sampling device also includes a controller; The controller is used to power the sampling device via a cable and dynamically receive data collected by each sensor in the sampling device.

9. The in-situ fluid sampling device for natural gas hydrate reservoirs according to claim 8, characterized in that, The sampling device also includes an interactive terminal; The interactive terminal is used to display, analyze, store, or replay data collected by various sensors in the sampling device; and to control the PVT sampling bucket to perform sampling in response to the operator's instructions.

10. A control method for an in-situ fluid sampling device for natural gas hydrate reservoirs, characterized in that, The control method, applied to the in-situ fluid sampling device for a natural gas hydrate reservoir as described in claim 1, includes the following steps: The upper and lower packers in the sampling device are controlled to set and seal, so as to form a sealed test area; The pump module is activated to extract formation fluids via probes. The target fluid is identified and sampled using the in-situ fluid identification and sampling module.

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