Offshore exploration well formation testing system and testing method

Abstract

The application discloses a marine exploration well formation testing system and a testing method thereof. The marine exploration well formation testing system comprises a liquid injection pipeline, a downhole testing tool assembly and a ground equipment assembly. The marine exploration well formation testing system is divided into the downhole testing tool assembly and the ground equipment assembly, full-link design of downhole pressure signal acquisition, signal conversion and ground signal receiving, decoding and display is realized, the pressure collector cooperates with the direct-reading tool to realize conversion of the pressure signal into a fluid pressure wave signal, the ground equipment assembly cooperates with the power fluid transmission and the pressure wave acquisition and decoding to realize real-time direct reading of the downhole pressure data, data playback is not needed in the middle, time efficiency is greatly improved during offshore operation, capital and time waste are reduced, meanwhile, the power fluid in the liquid injection pipeline is used as a pressure wave transmission medium, the offshore exploration well operation condition is adapted, transmission cables are not needed to be additionally laid, and operation complexity and cost are reduced.

Description

Technical Field

[0001] This invention relates to the field of oilfield drainage, and more particularly to a formation testing system and method for offshore exploration wells. Background Technology

[0002] Offshore exploratory wells typically refer to wells drilled during the oil and gas exploration phase, based on detailed seismic surveys, targeting local traps, new strata, or structural zones, with the aim of discovering oil and gas reservoirs, calculating controlled reserves, and predicting reserves. Generally, to evaluate the economic viability of newly discovered oil and gas reservoirs and scientifically formulate oil and gas field development plans, formation testing operations are conducted in exploratory wells to assess production capacity and determine the reservoir's potential. Formation testing refers to the entire process, conducted during drilling or after well completion, of establishing a channel connecting the formation to the well bottom, guiding formation fluids to the surface, and performing tests according to a specific procedure to determine the formation fluid productivity, properties, formation pressure, temperature, and dynamic characteristics.

[0003] Oil and gas reservoir production varies. High-production reservoirs can achieve self-flowing drainage using formation energy, while lower-production reservoirs or those aiming for higher surface production require artificial lift techniques. Currently, commonly used drainage techniques in offshore exploration well formation testing include coiled tubing nitrogen lift, coiled tubing hydraulic lift, ESP, screw pumps, and traditional jet pumps. Each artificial lift technique has its applicable scope and matching drainage method. When using coiled tubing hydraulic lift during testing, limitations such as testing tool control methods, operational timeliness, and cost prevent the real-time transmission of downhole pressure data using cables installed inside the test string and repeaters connected externally. Currently, only storage pressure gauges installed with the pump core in the tubing record downhole pressure and temperature changes. After the operation, the pump core and pressure gauge are retrieved to replay the pressure and temperature data. In complex situations or pressure-sensitive reservoirs, the pump core must be retrieved midway to install pressure gauges for data playback to decide on the next steps, severely impacting the timeliness of offshore operations and resulting in significant waste of funds and time.

[0004] Currently, there is no system or method for real-time acquisition of downhole pressure data in offshore exploration well formation testing operations. Summary of the Invention

[0005] The technical problem to be solved by the present invention is to provide a formation testing system and testing method for offshore exploration wells.

[0006] The technical solution adopted by the present invention to solve its technical problem is: to construct an offshore exploration well formation testing system, which includes a liquid injection pipeline, a downhole testing tool assembly and a surface equipment assembly; The downhole testing tool assembly includes a direct reading tool and a pressure acquisition device. The pressure acquisition device is used to acquire downhole pressure signals, and the direct reading tool is used to receive the downhole pressure signals and convert them into pressure wave signals that can propagate in fluids. The ground equipment components include a liquid tank, an injection pump, a signal acquisition sensor, and a ground decoding system; The liquid tank is used to store the power fluid to be delivered downhole, the injection pump is used to pump the power fluid in the liquid tank into the liquid injection pipeline, and the signal acquisition sensor is used to acquire pressure wave signals. The ground decoding system is communicatively connected to the signal acquisition sensor and is used to denoise, demodulate, and restore the downhole pressure signal of the acquired pressure wave signal.

[0007] In some embodiments, the direct reading tool includes a signal generating mechanism, a pulse generator motor, a pressure signal receiver, and a communication interface; The communication interface is electrically connected to the pressure signal receiver. The pressure signal receiver receives the downhole pressure digital signal transmitted by the pressure acquisition device through the communication interface and transmits the downhole pressure digital signal to the pulse generator motor. The pulse generator motor is connected to the signal generating mechanism. After receiving the downhole pressure digital signal, the pulse generator motor converts it into a preset mechanical motion to drive the signal generating mechanism to generate pressure fluctuations in the pressurized power fluid in the liquid injection pipeline.

[0008] In some embodiments, the direct reading tool further includes a continuous tubing connector, an upstream coupling, a protective sleeve, a power supply system, and a downstream coupling; One end of the continuous tubing connector is mechanically sealed to the liquid injection line, and the other end is connected to one end of the upstream variable coupling; The other end of the upstream buckle is connected to the upper end of the protective cylinder, and the lower end of the protective cylinder is connected to one end of the downstream buckle. The continuous tubing connector, the upstream variable coupling, the protective sleeve, and the downstream variable coupling are all provided with flow holes inside. Each flow hole is coaxially connected and connected to the internal channel of the liquid injection pipeline, forming the delivery channel of the power fluid. The power supply system is built into the cavity of the protective cylinder and is used to provide working power to the various components of the direct reading tool.

[0009] In some embodiments, the signal generating mechanism includes a structural component module and a parameter optimization module; The structural component module includes a stator, a protective cover, a rotor, a rotor fixing component, and a central shaft. The rotor is mounted on the central shaft via the rotor fixing component. The stator and the rotor cooperate to form a flow channel. The protective cover is provided on the outside of the stator and the rotor. The parameter optimization module is used to simulate the periodic change of the pressure drop of the signal generating mechanism over time, and to obtain the variation law of the pressure wave signal amplitude and the stator-rotor gap.

[0010] In some embodiments, both the stator and the rotor are made of hard alloy material, and the stator is provided with stress-reducing fillets, stress-reducing arcs, stress-reducing oblique fillets, and stress-reducing inclined surfaces.

[0011] In some embodiments, the ground decoding system has a built-in pulse signal processing unit; the pulse signal processing unit includes a downsampling conversion module, a baseband filtering module, an interference suppression module, and a baseline cancellation module; The downsampling transformation module integrates an anti-aliasing filter and a decimator to perform sampling transformation on the pressure wave signal input from the signal acquisition sensor. The baseband filtering module is an FIR low-pass filtering module, which is used to perform baseband filtering on the downsampled transformed signal to filter out out-of-band noise and interference in the signal. The interference suppression module is used to process the baseband filtered signal to eliminate pump-type interference aliased into the signal band. The baseline elimination module is used to estimate and subtract the baseline drift signal of the signal that has completed interference suppression, thereby achieving baseline elimination of the signal.

[0012] In this embodiment, a testing method for an offshore exploration well formation testing system is also constructed, which is based on the aforementioned offshore exploration well formation testing system and includes the following steps: S1. After completing drilling, casing running, and cementing operations, run the test string. S2. After the test string is lowered to a preset depth, the packer in the test string is set to isolate the communication between the test string and the annulus. Then, the perforating bullet in the test string is detonated. The perforating bullet penetrates the casing and cement sheath to establish a flow channel between the formation and the test wellbore, allowing the formation fluid to enter the test wellbore. S3. Observe the production of formation fluid. If it is determined to be low and artificial lift is required, lower the downhole test tool assembly to the preset position of the hydraulic lift working cylinder and start running the coiled tubing. After the formation fluid flows in through the channel of the downhole test tool assembly, the formation fluid mixes with the descending power fluid and rises along the annulus to the surface. S4. Start the injection pump to deliver the power fluid in the liquid tank to the downhole testing tool assembly through the liquid injection pipeline. A production pressure differential is formed at the downhole testing tool assembly. The pressure acquisition device collects downhole pressure and temperature data through the pressure transmission channel of the downhole testing tool assembly and converts it into an electrical signal, which is then transmitted to the pressure signal receiver. The pressure signal receiver converts the electrical signal into a digital signal and transmits it to the direct reading tool. After receiving the digital signal, the pulse generator motor drives the signal generating mechanism to generate a pressure wave signal carrying downhole pressure information in the pressurized power fluid. The pressure wave signal propagates upstream to the surface end using the power fluid in the liquid injection pipeline as the transmission channel. S5. The signal acquisition sensor acquires pressure wave signals in real time and transmits them to the ground decoding system. The ground decoding system performs noise reduction and demodulation processing on the pressure wave signals in sequence, restores and displays the downhole pressure data in real time, and realizes direct reading monitoring of downhole parameters.

[0013] In some embodiments, the procedure further includes step S6, operation completion: after completing the drainage metering, the pressure and flow rate of the injection pump are reduced, the coiled tubing and the wellhead of the offshore exploration well formation testing system are raised, and then the surface test shut-in procedure is initiated, or the surface test tree is removed, the packer is unsealed, the test string is pulled out, and the subsequent well kill procedure is executed.

[0014] In some embodiments, in step S1, the bottom of the test string is equipped with an APR tool and a built-in perforation gun, the upper part is a drill pipe or tubing and the hydraulic lift working cylinder is connected in the middle section of the test string, the wellhead is equipped with the surface test tree, and the surface equipment components are placed and connected on the surface, and the surface and downhole tubing lines are pressure tested.

[0015] In some embodiments, in step S4, the pressure acquisition device employs a redundant design with two pressure measurement points.

[0016] The implementation of this invention has the following beneficial effects: The offshore exploration well formation testing system is divided into downhole testing tool components and surface equipment components, realizing a full-link design of downhole pressure signal acquisition, signal conversion and surface signal reception, decoding and display. The pressure acquisition device and the direct reading tool work together to convert the pressure signal into a fluid pressure wave signal. The surface equipment components achieve real-time direct reading of downhole pressure data through the coordinated work of power fluid delivery and pressure wave acquisition and decoding, without the need to retrieve the tool midway to replay the data, which greatly improves the efficiency of offshore operations and reduces the waste of money and time. At the same time, the power fluid in the liquid injection pipeline is used as the pressure wave transmission medium, which is suitable for the working conditions of offshore exploration wells, eliminating the need to lay additional transmission cables and reducing the complexity and cost of operations. This offshore exploration well formation testing system solves the problem of not being able to obtain downhole pressure data in real time during offshore coiled tubing hydraulic lift, thus making it impossible to reasonably control the production pressure differential. By adopting this offshore exploration well formation testing system, the problem of inaccurate production evaluation caused by the lack of real-time downhole pressure data can be solved, and formation productivity can be evaluated more accurately. It can provide effective decision data for surface pump pressure control, reduce operational risks, effectively reduce the number of coiled tubing trips and runs, and improve operational efficiency. Attached Figure Description

[0017] To more clearly illustrate the technical solution of the present invention, the present invention will be further described below in conjunction with the accompanying drawings and embodiments. It should be understood that the following drawings only show some embodiments of the present invention and should not be considered as a limitation of the scope. For those skilled in the art, other related drawings can be obtained from these drawings without creative effort. In the drawings: Figure 1 This is a schematic diagram of the overall structure of the offshore exploration well formation testing system in some embodiments of the present invention; Figure 2 These are schematic diagrams of the direct-reading tool in some embodiments of the present invention; Figure 3 These are schematic diagrams of the signal generating mechanism in some embodiments of the present invention; Figure 4 This is a schematic diagram of the stator structure in some embodiments of the present invention. Detailed Implementation

[0018] To provide a clearer understanding of the technical features, objectives, and effects of this invention, specific embodiments are now described in detail with reference to the accompanying drawings. In the following description, it should be understood that the orientations or positional relationships indicated by terms such as "front," "rear," "upper," "lower," "left," "right," "longitudinal," "horizontal," "vertical," "horizontal," "top," "bottom," "inner," "outer," "head," and "tail" are based on the orientations or positional relationships shown in the accompanying drawings, and are constructed and operated in a specific orientation. They are only for the convenience of describing this technical solution and do not indicate that the device or element referred to must have a specific orientation; therefore, they should not be construed as limitations on this invention.

[0019] It should also be noted that, unless otherwise explicitly specified and limited, terms such as "installation," "connection," "linking," "fixing," and "setting" should be interpreted broadly. For example, they can refer to a fixed connection, a detachable connection, or an integral part; they can refer to a mechanical connection or an electrical connection; they can refer to a direct connection or an indirect connection through an intermediate medium; they can refer to the internal communication of two components or the interaction between two components. When an component is referred to as being "on" or "below" another component, the component can be located "directly" or "indirectly" on the other component, or there may be one or more intermediary components. The terms "first," "second," "third," etc., are only for the convenience of describing this technical solution and should not be construed as indicating or implying relative importance or implicitly specifying the number of indicated technical features. Therefore, features defined with "first," "second," "third," etc., may explicitly or implicitly include one or more of that feature. For those skilled in the art, the specific meaning of the above terms in this invention can be understood according to the specific circumstances.

[0020] Please see Figures 1 to 4 This is a formation testing system for offshore exploration wells, as described in some embodiments of the present invention. It includes a liquid injection pipeline 1, a downhole testing tool assembly, and a surface equipment assembly. The downhole testing tool assembly includes a direct-reading tool 2 and a pressure acquisition unit 3. The pressure acquisition unit 3 is used to acquire downhole pressure signals, and the direct-reading tool 2 is used to receive the downhole pressure signals and convert them into pressure wave signals that can propagate in fluid. The surface equipment assembly includes a liquid tank 4, an injection pump 5, a signal acquisition sensor 6, and a surface decoding system 7. The liquid tank 4 is used to store the power fluid to be delivered downhole. The injection pump 5 is used to pump the power fluid from the liquid tank 4 into the liquid injection pipeline 1. The signal acquisition sensor 6 is used to acquire pressure wave signals. The surface decoding system 7 is communicatively connected to the signal acquisition sensor 6 and is used to denoise, demodulate, and restore the downhole pressure signals for display.

[0021] Specifically, the pressure acquisition unit 3 is used to collect downhole pressure data and transmit it to the pressure signal receiver 23 described below. The direct-reading tool 2 has the function of receiving downhole pressure digital signals and can encode the pressure signal in a certain way, then use its own pulse motor 22 to drive the signal generating mechanism 21 to generate a pressure wave signal. The direct-reading tool 2 also has temperature-resistant, pressure-resistant, and low-power power supply functions, enabling it to convert digital pressure signals into fluid pressure wave signals for upstream transmission. The liquid injection pipeline 1 serves as the channel for pumping in fluid and the signal channel for transmitting pressure wave signals. The signal acquisition sensor 6 is used to collect surface pressure wave signals and transmit them to the surface decoding system 7 via a wired connection. The surface decoding system 7 receives the surface pressure wave signals, performs noise reduction and demodulation, and displays the downhole pressure signals in real time.

[0022] Understandably, this offshore exploration well formation testing system is divided into downhole testing tool components and surface equipment components, realizing a full-link design of downhole pressure signal acquisition, signal conversion and surface signal reception, decoding and display. The pressure acquisition unit 3 and the direct reading tool 2 work together to convert the pressure signal into a fluid pressure wave signal. The surface equipment components achieve real-time direct reading of downhole pressure data through the coordinated work of power fluid delivery and pressure wave acquisition and decoding, without the need to retrieve the tool midway to replay the data, which greatly improves the efficiency of offshore operations and reduces the waste of money and time. At the same time, the power fluid in the liquid injection pipeline 1 is used as the pressure wave transmission medium, which is suitable for the working conditions of offshore exploration wells, eliminating the need to lay additional transmission cables and reducing the complexity and cost of operations. This offshore exploration well formation testing system solves the problem of not being able to obtain downhole pressure data in real time during offshore coiled tubing hydraulic lift, thus making it impossible to reasonably control the production pressure differential. By adopting this offshore exploration well formation testing system, the problem of inaccurate production evaluation caused by the lack of real-time downhole pressure data can be solved, and formation productivity can be evaluated more accurately. It can provide effective decision data for surface pump pressure control, reduce operational risks, effectively reduce the number of coiled tubing trips and runs, and improve operational efficiency.

[0023] like Figure 2As shown, the direct reading tool 2 includes a signal generating mechanism 21, a pulse motor 22, a pressure signal receiver 23, and a communication interface 24. The communication interface 24 is electrically connected to the pressure signal receiver 23. The pressure signal receiver 23 receives the downhole pressure digital signal transmitted by the pressure acquisition unit 3 through the communication interface 24 and transmits the downhole pressure digital signal to the pulse motor 22. The pulse motor 22 is driven by the signal generating mechanism 21. After receiving the downhole pressure digital signal, the pulse motor 22 converts it into a preset mechanical motion to drive the signal generating mechanism 21 to generate pressure fluctuations in the pressurized dynamic fluid of the liquid injection pipeline 1, forming a pressure wave signal carrying downhole pressure information. The pressure wave signal propagates upstream to the surface end using the dynamic fluid in the liquid injection pipeline 1 as the transmission medium. Through the step-by-step coordination of communication interface 24, pressure signal receiver 23, pulse motor 22, and signal generating mechanism 21, the downhole pressure signal is accurately converted from digital signal to mechanical motion, and then to fluid pressure wave signal. Pressure signal receiver 23 ensures stable reception of the downhole pressure digital signal, while pulse motor 22 converts the digital signal into a preset mechanical motion, ensuring that the pressure wave signal generated by signal generating mechanism 21 accurately carries downhole pressure information. The pressure wave propagation method using power fluid as the transmission medium is compatible with the coiled tubing hydraulic lift process in offshore exploration wells. The signal transmission path overlaps with the power fluid delivery path, eliminating the need for an additional signal transmission channel and improving the system's integration and adaptability.

[0024] The direct-reading tool 2 also includes a continuous tubing connector 25, an upstream transformer 26, a protective sleeve 27, a power supply system 28, and a downstream transformer 29. One end of the continuous tubing connector 25 is mechanically sealed to the liquid injection line 1, and the other end is connected to one end of the upstream transformer 26. The other end of the upstream transformer 26 is connected to the upper end of the protective sleeve 27, and the lower end of the protective sleeve 27 is connected to one end of the downstream transformer 29. The continuous tubing connector 25, the upstream transformer 26, the protective sleeve 27, and the downstream transformer 29 are all provided with flow holes inside. Each flow hole is coaxially connected and connected to the internal channel of the liquid injection line 1, forming a power fluid delivery channel. The power supply system 28 is built into the cavity of the protective sleeve 27 and is used to provide working power to the various components of the direct-reading tool 2.

[0025] Specifically, the coiled tubing connector 25 serves to mechanically connect the upstream coiled tubing to the downhole tool. It features a coiled tubing connection thread upstream, a tool connection thread downstream, and a flow passage in the middle for power fluid delivery. The downhole direct-reading tool 2 is an INSERT type. Due to this structure, the internal functional components of the tool 2 have a large diameter. When designing the protective sleeve 27, the inner diameter of the central functional component insertion port is designed to be large. Because of the size limitations of the male and female threads, a female thread design is required here. Therefore, the main function of the upstream variable thread 26 is to connect the downhole tool to the upstream tool. Additionally, the protective sleeve 27 connects upstream to the upstream variable thread 26 and downstream to the pressure signal receiver 23. The protective sleeve 27 houses the functional components and delivers power fluid to the downstream bottom of the well. Externally, it connects to the annulus 10 on the well wall to deliver a mixture carrying crude oil back to the surface and flow into the working fluid tank. Simultaneously, the protective sleeve 27 also provides drilling pressure resistance, tensile, compressive, bending, and torsional resistance, vibration resistance, high temperature and high pressure resistance, and protection for the internal functional components. Furthermore, the pulse generator motor 22 drives the signal generating mechanism 21 to move, causing it to generate pressure fluctuations in the pressurized fluid. This pressure wave signal can carry downhole pressure information and propagate upstream in the power fluid. The pressure wave signal propagating in the power fluid is essentially generated by the compressibility of the power fluid. The power supply system 28 is used to power the components of the downhole direct reading tool 2. The pressure signal receiver 23 is used to receive downhole pressure electrical signals and transmit them to the pulse generator drive control system. The communication interface 24 completes communication with the pressure signal receiver 23. The downstream variable connector 29 has the same function as the upstream variable connector 26, that is, the outer diameter of the internal function of the test tool is relatively large. Due to the size limitations of the male and female connectors, it needs to be designed as a female connector. Therefore, the main function of the downstream variable connector 29 is to realize the connection between the downhole tool and the downstream tool.

[0026] Understandably, the sequential connection of the continuous tubing connector 25, upstream coupling 26, protective sleeve 27, and downstream coupling 29 achieves a reliable mechanical seal connection between the direct reading tool 2, the liquid injection pipeline 1, and the downhole testing tool. This adapts to the small inner diameter requirements of offshore exploration well testing strings, ensuring the tool's downhole passability. The flow holes inside each component are coaxially connected, forming a power fluid delivery channel connected to the liquid injection pipeline 1, ensuring smooth power fluid delivery and not affecting hydraulic lift and drainage operations. The power supply system 28 is built into the cavity of the protective sleeve 27, providing integrated power to all components of the direct reading tool 2. The protective sleeve 27 provides protection against high temperature, high pressure, vibration, tension, compression, bending, and torsion for the power supply system 28 and other functional components, adapting to the complex downhole operating environment and improving the tool's reliability and service life.

[0027] In addition, the outer diameter of the direct reading tool 2 does not exceed 71mm, meeting the inner diameter limit requirements for testing tools. The miniaturized design of the direct reading tool 2 solves the problem that conventional downhole signal transmission tools have excessively large outer diameters and cannot be used in small-diameter test strings, ensuring that the tool can be smoothly lowered into the well and work normally without affecting the normal flow of formation fluids, thus improving the applicability and compatibility of the system.

[0028] like Figure 3 As shown, the signal generating mechanism 21 includes a structural component module and a parameter optimization module. The structural component module includes a stator 211, a protective cover 212, a rotor 213, a rotor fixing component 214, and a central shaft 215. The rotor 213 is mounted on the central shaft 215 via the rotor fixing component 214. The stator 211 and rotor 213 cooperate to form a flow channel. The protective cover 212 covers the outside of the stator 211 and rotor 213. The parameter optimization module is used to simulate the periodic change of pressure drop in the signal generating mechanism 21 over time, obtain the variation law of the pressure wave signal amplitude and the stator-rotor gap, and select the stator-rotor gap interval corresponding to the highest amplitude according to the downhole pressure data transmission rate requirements. The structural component module forms a flow channel through the cooperation of the stator 211 and rotor 213. The rotor 213 swings with the central shaft 215 to achieve periodic changes in the flow area, thereby generating a pressure wave signal. The protective cover 212 effectively protects the stator and rotor structure, preventing damage from downhole fluid impurities. The parameter optimization module conducts simulations of the periodic changes in pressure drop to obtain the variation law of pressure wave amplitude and stator-rotor gap. Based on the requirements of pressure data transmission rate, it selects the range of the highest pressure wave amplitude, thereby achieving precise optimization of the parameters of the signal generating mechanism 21. This solves the technical problem of weak pressure wave amplitude under low displacement in the existing technology, ensuring that the pressure wave signal still has sufficient amplitude under extremely low displacement conditions and can stably propagate to the upstream ground end, thus improving the reliability of signal transmission.

[0029] like Figure 4As shown, both the stator 211 and rotor 213 are made of cemented carbide. The stator 211 is equipped with stress-reducing fillets 221, stress-reducing arcs 222, stress-reducing oblique fillets 223, and stress-reducing inclined surfaces 224. The use of cemented carbide for the stator 211 and rotor 213 provides high strength and high wear resistance, enabling it to withstand the complex environment of high pressure and high wear in downhole drilling, thus extending the service life of components. Simultaneously, the stator 211 incorporates multiple stress-reducing structures, effectively solving the problem of stress concentration in cemented carbide materials. This prevents component breakage due to miniaturization, ensuring the structural stability and maneuverability of the stator 211 in its small size. This provides material and structural guarantees for the miniaturization design of the direct-reading tool 2, allowing it to adapt to the small-diameter requirements of the test string. In a specific embodiment, stress concentration reduction design was implemented for the stator 211, and water circulation tests were conducted. The results show that the miniaturized cemented carbide stator 211 solves the maneuverability problem caused by miniaturization.

[0030] The stator 211 has an outer diameter of 48mm to 52mm, the rotor 213 has an outer diameter of 36mm to 40mm, and the gap between the stator 211 and the rotor 213 is 1mm. The stator 211 has a slot with an outer diameter of 20mm to 22mm, a distance of 11mm to 13mm between the slot and the center of the stator 211, an exit angle of 41° to 45°, and an entrance angle of 56° to 60°. Preferably, the protective cover 212 has an outer diameter of 55mm, the stator 211 has an outer diameter of 50mm, the rotor 213 has an outer diameter of 38mm, the gap between the stator 211 and the rotor 213 is 1mm, the slot has an outer diameter of 21mm, a distance of 12mm between the slot and the center of the stator 211, an exit angle of 43°, and an entrance angle of 58°. The fit between the 50mm outer diameter of stator 211 and the 38mm outer diameter of rotor 213, combined with a 1mm stator-rotor clearance, ensures both the flexibility of rotor 213's oscillation and reduces power fluid leakage, allowing rotor 213 to effectively change the flow area of ​​stator 211's flow channels during oscillation. Simultaneously, the 21mm outer diameter of the slot and the 12mm center distance between the slot and stator 211 match the power fluid flow requirements, ensuring sufficient flow velocity even at extremely low displacements. Combined with the optimized 43° slot outlet angle and 58° slot inlet angle, fluid flow resistance is reduced, improving the triggering efficiency of water hammer effects, resulting in stable pressure wave amplitude and high recognition, ensuring effective transmission of downhole data. The innovation of this key technology lies in achieving stable operation of the signal generation mechanism 21 at extremely low displacements by modifying the structural parameters of stator 211 and rotor 213 through fluid simulation and pressure drop law research.

[0031] Furthermore, pressure waves are essentially hydroelastic waves, with upstream and downstream fluid channels as transmission channels. Upstream, the pressure wave propagates along the hydroelastic fluid inside the coiled tubing to the surface. Due to the friction of the coiled tubing wall, the amplitude of the pressure wave gradually weakens during transmission. Downstream, the pressure wave propagates along the hydroelastic fluid inside the tool to the bottom of the well. Changes in diameter at the bottom of the well and inside the tool cause reflections of the pressure wave. These reflected waves continue to propagate upstream to the surface, coupling with the original signal and causing signal distortion. This process repeats, resulting in multiple harmonics of different attenuation levels, further distorting the signal. This, combined with coupling interference from tool vibration, wellbore vibration, and pump noise, leads to weak signals acquired by surface sensors and makes decoding difficult.

[0032] The ground decoding system 7 has a built-in pulse signal processing unit. This unit includes a downsampling transformation module, a baseband filtering module, an interference suppression module, and a baseline cancellation module. The downsampling transformation module integrates an anti-aliasing filter and a decimator to perform sampling transformation on the pressure wave signal input from the signal acquisition sensor 6. The baseband filtering module is an FIR low-pass filter module used to perform baseband filtering on the downsampling transformed signal, removing out-of-band noise and interference. The interference suppression module is used to process the baseband filtered signal, eliminating pump-like interference aliased into the signal band. The baseline cancellation module estimates and subtracts the baseline drift signal from the interference-suppressed signal, achieving baseline cancellation. The pulse signal processing unit works as follows: first, a 1 / 3 downsampling transformation is achieved through an anti-aliasing filter and a 3x decimator to reduce the signal sampling rate and subsequent computational load; then, a FIR low-pass filter is used for baseband filtering to remove out-of-band noise and interference. Based on this, specialized interference suppression is performed to eliminate aliasing interference such as pump surges within the signal band. Finally, baseline elimination is achieved by estimating and subtracting baseline drift signals, thus ensuring the accuracy and stability of signal processing. Understandably, through the step-by-step processing of the downsampling transformation module, baseband filtering module, interference suppression module, and baseline elimination module, accurate decoding and recovery of extremely weak pressure wave signals are achieved. The downsampling transformation module reduces the signal sampling rate, decreases subsequent computational load, and improves signal processing efficiency; the baseband filtering module filters out out-of-band noise and interference; the interference suppression module eliminates in-band interference such as pump surges; and the baseline elimination module subtracts baseline drift signals. The collaborative work of these multiple modules effectively solves the technical challenge of weak pressure wave signals and susceptibility to noise at low displacement rates, ensuring that the surface decoding system 7 can accurately reconstruct downhole pressure signals and improve the detection accuracy of pressure data.

[0033] The specific working principle of this offshore exploration well formation testing system is as follows: First, according to... Figure 2 Complete the connection of the direct reading tool 2, and link it. Figure 1In accordance with the corresponding structure, ground installation work is carried out. Signal acquisition sensor 6 is installed near injection pump 5. Ground decoding system 7 is deployed to the well site control room and connected to signal acquisition sensor 6 via cable. Then, injection pump 5 is started according to the system's preset parameters to run the system. After the system is running, the entire process of downhole signal acquisition and transmission and ground signal acquisition and decoding is completed sequentially: First, pressure acquisition device 3 acquires downhole pressure signals through a redundant design with dual pressure measurement points. Then, its internal circuitry converts the pressure signals into electromagnetic wave signals, which are transmitted to pressure signal receiver 23 via short-range wireless electromagnetic transmission. Pressure signal receiver 23 then... After the received electromagnetic wave signal is converted into a digital signal, the direct-reading tool 2, relying on its integrated power supply system 28, pulse motor 22, and signal generation mechanism 21, works in concert. The pulse motor 22 converts the pressure digital signal into a pressure wave signal of the power fluid through the signal generation mechanism 21. This pressure wave signal propagates upstream to the surface end through the fluid in the liquid injection pipeline 1, completing the acquisition and transmission of downhole signals. At the surface end, the signal acquisition sensor 6 acquires the pressure wave signal in real time and transmits it to the surface decoding system 7 via a wired connection. After noise reduction and demodulation processing by the surface decoding system 7, the downhole pressure signal is displayed in real time. The entire process realizes the real-time acquisition, transmission, and surface decoding of downhole pressure data, enabling surface technicians to monitor the downhole pressure fluctuation status in real time, facilitating timely adjustment of formation pressure, reasonable control of formation pressure changes, and thus more accurately completing formation productivity evaluation.

[0034] In this embodiment, a testing method for an offshore exploration well formation testing system is also constructed, which is based on the above-mentioned offshore exploration well formation testing system and specifically includes the following steps: S1. After completing drilling, casing running, and cementing operations, run the test string. S2. After lowering the test string to the preset depth, set the packer in the test string to isolate the connection between the test string and the annulus 10. Then detonate the perforating bullet in the test string. The perforating bullet penetrates the casing and cement sheath to establish a flow channel between the formation and the test wellbore, allowing the formation fluid to enter the test wellbore. S3. Observe the production of formation fluid. If it is determined to be low and artificial lift is required, lower the downhole test tool assembly to the preset position of the hydraulic lift working cylinder and start running the coiled tubing. After the formation fluid flows in through the channel of the downhole test tool assembly, the formation fluid mixes with the descending power fluid and then rises along the annulus 10 to the surface. S4. Start the injection pump 5 to transport the power fluid in the liquid tank 4 to the downhole test tool assembly through the liquid injection pipeline 1. A production pressure differential is formed at the downhole test tool assembly. The pressure acquisition device 3 collects downhole pressure and temperature data through the pressure transmission channel of the downhole test tool assembly and converts it into an electrical signal, which is then transmitted to the pressure signal receiver 23. The pressure signal receiver 23 converts the electrical signal into a digital signal and transmits it to the direct reading tool 2. After receiving the digital signal, the pulse motor 22 drives the signal generating mechanism 21 to generate a pressure wave signal carrying downhole pressure information in the pressurized power fluid. The pressure wave signal propagates upstream to the surface end through the power fluid in the liquid injection pipeline 1 as the transmission channel. S5 and signal acquisition sensor 6 acquire pressure wave signals in real time and transmit them to the ground decoding system 7. The ground decoding system 7 performs noise reduction and demodulation processing on the pressure wave signals in sequence, restores and displays the downhole pressure data in real time, and realizes direct reading monitoring of downhole parameters.

[0035] In step S1, the test string is equipped with an APR tool and a built-in perforation gun at the bottom, with drill pipe or tubing at the top and a hydraulic lift working cylinder connected in the middle section. A surface test tree is installed at the wellhead. Simultaneously, the surface equipment components are placed and connected on the surface, and pressure tests are conducted on the surface and downhole tubing lines. Specifically, after drilling, casing, and cementing operations are completed, the downhole tools are connected sequentially from bottom to top on the drilling rig according to the test string diagram, and the threads are tightened. The test string is continuously lowered, with an APR tool and a built-in perforation gun at the bottom, drill pipe at the top, and a hydraulic lift working cylinder connected in the middle. The connection depth of the hydraulic lift working cylinder is determined according to the maximum design production pressure differential. A surface test tree is installed at the wellhead. Simultaneously, the liquid tank 4, injection pump 5, signal acquisition sensor 6, and surface decoding system 7 are placed and connected on the surface, and pressure tests are conducted on the surface and downhole tubing lines to ensure sealing. APR tools are annular pressure-responsive tools, which are core downhole tool strings used for formation testing in oil exploration and development. They belong to pressure-controlled full-bore testing tools.

[0036] Step S3 specifically involves: after ground observation and determining that the production is low, the continuous tubing is lowered. The continuous tubing is a hollow, continuous metal tube with the same inner and outer diameters, capable of withstanding high pressure. The end of the continuous tubing is connected to the components of the direct reading tool 2 via threaded connections, until it is lowered into the hydraulic lifting working cylinder, forming... Figure 1The structure shown is a coiled tubing, i.e., the fluid injection line 1. After entering the wellbore, the formation fluid, confined by the packer, travels upwards along the inside of the test string, flows in through a specific, unique channel within the downhole testing tool assembly, mixes with the descending fluid, and then ascends to the surface via the annulus 10. Furthermore, since the inside of the test string is unobstructed after perforation, the formation fluid production can be observed at the surface. If the production is high, oil, gas, or liquid production will be observed. However, in deep, low-porosity reservoirs, production is generally very low, and formation energy alone cannot reach the surface; therefore, artificial lift technology must be employed.

[0037] In step S4, the pressure acquisition device 3 adopts a redundant design with two pressure measurement points. The two pressure measurement points in the redundant design have the same function and synchronously collect downhole pressure and temperature data, which can effectively avoid the signal acquisition interruption problem caused by the failure of a single pressure measurement point, and improve the reliability and accuracy of pressure signal acquisition.

[0038] The testing method for the offshore exploration well formation testing system also includes step S6, operation completion: After completing the fluid discharge metering, reduce the pressure and flow rate of the injection pump 5, raise the coiled tubing along with the components of the offshore exploration well formation testing system to the wellhead, and then proceed to the surface test shut-in procedure, or sequentially remove the surface test tree, unseal the packer, retrieve the test string, and execute the subsequent well control procedure. Specifically, after completing the fluid discharge metering, reduce the pressure and flow rate of the injection pump 5, raise the coiled tubing along with the test tools, pressure signal receiver 23, direct reading tool 2, and matching pulse generator motor 22 and signal generator 21 to the wellhead, and according to the operational requirements of this test, proceed to the surface test shut-in procedure to carry out subsequent formation pressure recovery testing. If the test is completed, sequentially remove the surface test tree, unseal the packer, retrieve the test string, and execute the well control procedure to complete the entire offshore exploration well formation testing operation.

[0039] Understandably, the testing method of this offshore exploration well formation testing system, through its step-by-step design—including well foundation construction, containment and perforation operations, coiled tubing and downhole tool deployment, fluid drainage and downhole signal acquisition and transmission, and surface signal processing and direct reading—achieves integrated operation of fluid drainage and real-time direct reading of downhole pressure in offshore exploration wells. The steps are tightly integrated and adaptable to conventional offshore exploration well operations, requiring no significant modification to existing processes, thus demonstrating strong practicality. This method can simultaneously complete the real-time acquisition, transmission, and surface decoding of downhole pressure signals during manual fluid drainage, enabling direct monitoring of downhole parameters. Technicians can adjust the production pressure differential promptly based on real-time pressure data, improving the accuracy of formation productivity evaluation, providing effective decision-making data for surface pump pressure control, and reducing operational risks.

[0040] It is understood that the above embodiments only illustrate preferred embodiments of the present invention, and their descriptions are relatively specific and detailed, but they should not be construed as limiting the scope of the present invention. It should be noted that those skilled in the art can freely combine the above technical features without departing from the concept of the present invention, and can also make several modifications and improvements, all of which fall within the protection scope of the present invention. Therefore, all equivalent transformations and modifications made with respect to the scope of the claims of the present invention should fall within the scope of the claims of the present invention.

Claims

1. A formation testing system for offshore exploration wells, characterized in that, Includes liquid injection piping (1), downhole testing tool components, and surface equipment components; The downhole testing tool assembly includes a direct reading tool (2) and a pressure acquisition device (3). The pressure acquisition device (3) is used to acquire downhole pressure signals, and the direct reading tool (2) is used to receive the downhole pressure signals and convert them into pressure wave signals that can propagate in fluids. The ground equipment components include a liquid tank (4), an injection pump (5), a signal acquisition sensor (6), and a ground decoding system (7); The liquid tank (4) is used to store the power fluid to be transported downhole, the injection pump (5) is used to pump the power fluid in the liquid tank (4) into the liquid injection pipeline (1), and the signal acquisition sensor (6) is used to acquire pressure wave signals. The ground decoding system (7) is communicatively connected to the signal acquisition sensor (6) and is used to denoise, demodulate and restore the downhole pressure signal of the acquired pressure wave signal.

2. The offshore exploration well formation testing system according to claim 1, characterized in that, The direct reading tool (2) includes a signal generating mechanism (21), a pulse generator motor (22), a pressure signal receiver (23), and a communication interface (24). The communication interface (24) is electrically connected to the pressure signal receiver (23). The pressure signal receiver (23) receives the downhole pressure digital signal transmitted by the pressure acquisition device (3) through the communication interface (24) and transmits the downhole pressure digital signal to the pulse generator motor (22). The pulse generator motor (22) is connected to the signal generating mechanism (21) for transmission. After receiving the downhole pressure digital signal, the pulse generator motor (22) converts it into a preset mechanical motion to drive the signal generating mechanism (21) to generate pressure fluctuations in the pressurized power fluid in the liquid injection pipeline (1).

3. The offshore exploration well formation testing system according to claim 2, characterized in that, The direct reading tool (2) also includes a continuous tubing connector (25), an upstream adapter (26), a protective sleeve (27), a power supply system (28), and a downstream adapter (29). One end of the continuous tubing connector (25) is mechanically sealed to the liquid injection line (1), and the other end is connected to one end of the upstream variable coupling (26); The other end of the upstream buckle (26) is connected to the upper end of the protective cylinder (27), and the lower end of the protective cylinder (27) is connected to one end of the downstream buckle (29); The continuous oil pipe joint (25), the upstream variable buckle (26), the protective cylinder (27) and the downstream variable buckle (29) are all provided with flow holes. Each flow hole is coaxially connected and connected to the internal channel of the liquid injection pipeline (1) to form the power fluid delivery channel. The power supply system (28) is built into the cavity of the protective cylinder (27) and is used to provide working power to each component of the direct reading tool (2).

4. The offshore exploration well formation testing system according to claim 2, characterized in that, The signal generating mechanism (21) includes a structural component module and a parameter optimization module; The structural component module includes a stator (211), a protective cover (212), a rotor (213), a rotor fixing member (214), and a central shaft (215). The rotor (213) is mounted on the central shaft (215) through the rotor fixing member (214). The stator (211) and the rotor (213) cooperate to form a flow channel. The protective cover (212) covers the outside of the stator (211) and the rotor (213). The parameter optimization module is used to simulate the periodic change of the pressure drop of the signal generating mechanism (21) over time, and to obtain the variation law of the amplitude of the pressure wave signal and the gap between the stator and rotor.

5. The offshore exploration well formation testing system according to claim 4, characterized in that, The stator (211) and the rotor (213) are both made of hard alloy material, and the stator (211) is provided with stress weakening fillet (221), stress weakening arc (222), stress weakening oblique fillet (223) and stress weakening oblique surface (224).

6. The offshore exploration well formation testing system according to claim 1, characterized in that, The ground decoding system (7) has a built-in pulse signal processing unit; the pulse signal processing unit includes a downsampling conversion module, a baseband filtering module, an interference suppression module, and a baseline cancellation module; The downsampling transformation module integrates an anti-aliasing filter and a decimator to perform sampling transformation on the pressure wave signal input by the signal acquisition sensor (6); The baseband filtering module is an FIR low-pass filtering module, which is used to perform baseband filtering on the downsampled transformed signal to filter out out-of-band noise and interference in the signal. The interference suppression module is used to process the baseband filtered signal to eliminate pump-type interference aliased into the signal band. The baseline elimination module is used to estimate and subtract the baseline drift signal of the signal that has completed interference suppression, thereby achieving baseline elimination of the signal.

7. A testing method for an offshore exploration well formation testing system, based on the offshore exploration well formation testing system according to any one of claims 1 to 6, characterized in that, Including the following steps: S1. After completing drilling, casing running, and cementing operations, run the test string. S2. After lowering the test string to a preset depth, the packer in the test string is set to isolate the connection between the test string and the annulus (10). Then, the perforating bullet in the test string is detonated. The perforating bullet penetrates the casing and cement sheath to establish a flow channel between the formation and the test wellbore, allowing the formation fluid to enter the test wellbore. S3. Observe the production of formation fluid. If it is determined that the production is low and artificial lifting is required, lower the downhole test tool assembly to the preset position of the hydraulic lifting working cylinder and start to lower the coiled tubing. After the formation fluid flows in through the channel of the downhole test tool assembly, the formation fluid mixes with the downward dynamic fluid and rises along the annulus (10) to the surface. S4. Start the injection pump (5) to transport the power fluid in the liquid tank (4) to the downhole test tool assembly through the liquid injection pipeline (1). A production pressure differential is formed at the downhole test tool assembly. The pressure acquisition device (3) collects downhole pressure and temperature data through the pressure transmission channel of the downhole test tool assembly and converts it into an electrical signal to be transmitted to the pressure signal receiver (23). The pressure signal receiver (23) converts the electrical signal into a digital signal and transmits it to the direct reading tool (2). After receiving the digital signal, the pulse motor (22) drives the signal generating mechanism (21) to generate a pressure wave signal carrying downhole pressure information in the pressurized power fluid. The pressure wave signal propagates to the upstream surface end with the power fluid in the liquid injection pipeline (1) as the transmission channel. S5. The signal acquisition sensor (6) acquires pressure wave signals in real time and transmits them to the ground decoding system (7). The ground decoding system (7) performs noise reduction and demodulation processing on the pressure wave signals in sequence, restores and displays the downhole pressure data in real time, and realizes direct reading monitoring of downhole parameters.

8. The testing method for the offshore exploration well formation testing system according to claim 7, characterized in that, It also includes step S6, operation completion: after completing the drainage metering, reduce the pressure and discharge of the injection pump (5), lift the coiled tubing and the wellhead of the offshore exploration well formation test system, and then switch to the surface test shut-in procedure, or sequentially remove the surface test tree, unseal the packer, pull out the test string, and execute the subsequent well kill procedure.

9. The testing method for the offshore exploration well formation testing system according to claim 7, characterized in that, In step S1, the bottom of the test string is equipped with an APR tool and a built-in perforation gun, the upper part is a drill pipe or tubing, and the hydraulic lift working cylinder is connected in the middle section of the test string. The wellhead is equipped with the surface test tree. At the same time, the surface equipment components are placed and connected on the ground, and the surface and downhole tubing lines are pressure tested.

10. The testing method for the offshore exploration well formation testing system according to claim 7, characterized in that, In step S4, the pressure acquisition device (3) adopts a redundant design with two pressure measurement points.

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