Negative pressure gas production device with optimized multi-modal fluid compression

Abstract

The present invention belongs to the technical field of gas collection and compression, and specifically relates to a negative-pressure gas collection device for optimizing multi-modal fluid compression. The device includes: a gas collection module, a fluid compression module, and a gas storage and transmission module; the gas collection module is used to cause formation gas to flow into the collection pipeline through negative pressure and transmit it to the fluid compression module; the fluid compression module includes a plurality of cascaded compressors, a dynamic pressure optimization control module, and a sensor module; the dynamic pressure optimization control module obtains gas parameters and environmental parameters during underground gas collection through the sensor module, and conveys the compressed gas to the gas storage and transmission module; the gas storage and transmission module is used to store the compressed gas and transmit the compressed gas to a remote end. The present invention improves gas recovery rate, reduces compression energy consumption, and effectively avoids problems such as unstable wellbore pressure and overloading of compressors.

Description

Technical Field

[0001] The present invention belongs to the technical field of gas collection and compression, and particularly relates to a negative-pressure gas production device for optimizing multi-modal fluid compression. Background Art

[0002] With the continuous increase in the depth and difficulty of oil and gas resource exploitation, traditional conventional oil and gas fields have gradually entered the stage of production decline, and unconventional resources such as shale gas, coalbed methane, and tight sandstone gas have gradually become the main growth points in current oil and gas exploration and development. However, these unconventional reservoirs often have characteristics such as deep burial, low porosity, and poor permeability, resulting in limited natural gas flow between the wellbore and the formation. Conventional positive-pressure gas production methods are difficult to fully utilize the production capacity of these reservoirs. To address this problem, various advanced techniques such as negative-pressure gas production, staged fracturing, and horizontal well technology have been successively proposed in the industry. Among them, negative-pressure gas production has attracted much attention because it can maintain a low pressure in the wellbore, thereby amplifying the pressure difference between the formation and the wellbore and significantly increasing the driving force of gas flow.

[0003] In the publicly available technical literature or patents, negative-pressure gas production is more often applied to unconventional gas reservoirs such as low-permeability gas reservoirs and shale gas reservoirs. The research focus is mainly concentrated on aspects such as the intensity and duration of downhole negative-pressure control and formation stability. For example, some existing technologies install vacuum pumps or negative-pressure devices at the wellhead to reduce the wellhead pressure, making it easier for formation gas to converge towards the wellbore to achieve the purpose of increasing production; there are also studies that have proposed a series of improvement measures for downhole packers and multiphase flow conditions to reduce the annulus pressure in the wellbore and stabilize gas production. However, the above-mentioned negative-pressure gas production methods often rely on single artificial experience or simple negative-pressure pumping control, lacking comprehensive optimization of multiple parameters such as gas flow rate, pressure, and temperature, and it is often difficult to carry out refined regulation when facing different depths and different permeability sections. In addition, these methods rarely systematically discuss the coupling problem between negative-pressure gas production and subsequent ground multi-stage compression systems, resulting in room for improvement in the overall efficiency from formation gas production to ground gathering and transportation.

[0004] On the other hand, multistage compression technology has been relatively maturely applied in the field of conventional natural gas production and transportation. Traditional multistage compressor systems usually adopt a fixed compression ratio or a single polytropic efficiency determined according to empirical data, and have limited adaptability to fluctuations in inlet gas and changes in composition. When the inlet pressure and composition of the gas change significantly, it is necessary to manually adjust the operating parameters of each stage of the compressor frequently. This not only involves complex operations but also often makes it difficult to achieve an optimal balance between energy utilization and gas production capacity. Some existing patents and literature propose to improve efficiency by increasing inter-stage cooling and precisely controlling the compressor speed. However, most studies still remain in the context of normal pressure or positive pressure gas production and do not fully consider the impact of wellbore negative pressure on the inlet pressure, so it is difficult to be directly applied to the unconventional situation of negative pressure gas production. Under negative pressure conditions, the gas pressure in the wellbore is often much lower than that in conventional production, resulting in more significant changes in the volume and viscosity of the gas during the process of entering the compressor. In addition, if the formation permeability is low and the pressure is uneven, it will also cause fluctuations in gas production, thus having a significant impact on the inlet parameters of the multistage compressor and making it difficult for traditional fixed ratio or approximate compression strategies to maintain high-efficiency operation. Summary of the Invention

[0005] In view of this, the main object of the present invention is to provide a negative pressure gas production device with optimized multimodal fluid compression, which enhances the gas production capacity of low-permeability gas reservoirs through negative pressure gas production and uses an intelligent control strategy for multistage compression to overcome the problem that traditional fixed compression ratio modes are difficult to adapt to gas flow fluctuations, ensuring that the system can maintain high-efficiency operation under different working conditions. Compared with the prior art, the present invention establishes a collaborative optimization model for negative pressure gas production and multistage compression, improves gas recovery rate, reduces compression energy consumption, and effectively avoids problems such as unstable wellbore pressure and compressor overload, providing a safer, more economical, and more intelligent solution for the efficient exploitation of unconventional gas reservoirs and low-permeability gas reservoirs.

[0006] The technical solution adopted by the present invention is as follows:

[0007] A negative pressure gas production device with optimized multimodal fluid compression, the device comprising: a gas collection module, a fluid compression module, and a gas storage and transmission module; the gas collection module is used to make formation gas flow to the collection pipeline through negative pressure and transmit it to the fluid compression module; the fluid compression module includes a plurality of cascaded compressors, a dynamic pressure optimization control module, and a sensor module; the dynamic pressure optimization control module obtains gas parameters and environmental parameters during underground gas collection through the sensor module, and adjusts the working mode and pressure output of each stage of the compressor in real time, and conveys the compressed gas to the gas storage and transmission module; the gas storage and transmission module is used to store the compressed gas and transmit the compressed gas to a remote end in response to a remote control instruction.

[0008] Further, the execution process of the dynamic pressure optimization control module specifically includes: establishing a flow model of gas in porous media under negative pressure conditions according to environmental parameters and gas parameters, and calculating the formation gas production; adjusting the intake pressure of the first-stage compressor to the safe intake pressure according to the formation gas production and in combination with gas parameters, and adjusting the inlet pressure, outlet pressure, inlet temperature, outlet temperature, compression power of each stage of the compressor, and the inter-stage cooling temperature drop between adjacent stages of the compressor according to the safe intake pressure and the required final discharge pressure.

[0009] Further, the environmental parameters include: formation absolute permeability , with a value range of 1 to 100, unit of mD; formation pressure , unit of Pa; formation temperature , unit of K; wellbore perforation area , unit of m²; formation porosity ; formation hydraulic pressure , unit of Pa; formation uniaxial compressive strength , unit of MPa; formation Poisson's ratio ; the gas parameters include: gas dynamic viscosity , unit of Pa·s; gas molecular weight , unit of g / mol; gas critical pressure , unit of MPa; gas critical temperature , unit of K; gas adiabatic index ; gas real-time temperature , unit of K; gas specific heat capacity , unit of kg·K; gas real-time pressure , unit of Pa.

[0010] Further, the formation gas production is calculated using the flow model:

[0011]

[0012] Among them, is the formation gas production, unit of kg / s; is the gas flow velocity in porous media, unit of m / s; is the gas density, unit of kg / m³.

[0013] Further, the gas flow velocity in porous media is calculated using the following formula:

[0014]

[0015] Among them, is the standard reference pressure, with a value of 101325Pa; is the standard reference temperature, with a value of 293.15K; the gas density is calculated using the following formula:

[0016]

[0017] where is the universal gas constant, with a value of 8.314 J / (mol·K); is the gas compressibility factor, which is calculated using the following formula:

[0018] .

[0019] Furthermore, the safe intake pressure is calculated through the following formula:

[0020]

[0021]

[0022] where is the critical formation collapse pressure; is the safe intake pressure, and the intake pressure of the first-stage compressor is adjusted to ; is the safety margin, with a value range of 50 to 100, and the unit is kPa; is the cross-sectional area of the intake pipeline, and the unit is m²; let be the inlet pressure of the -th stage compressor. For , it is of the intake pressure of the first-stage compressor, and for , it is the outlet pressure of the previous stage minus the pipeline pressure drop.

[0023] Furthermore, the outlet pressure of each stage of the compressor is adjusted through the following formula:

[0024]

[0025] where is the gas compressibility factor of the -th stage compressor; is the gas compressibility factor of the first-stage compressor; is the final discharge pressure; is the total number of compressor stages; is the -th stage compressor outlet pressure.

[0026] Furthermore, the inlet temperature, outlet temperature, and inter-stage cooling temperature drop of each stage of the compressor are adjusted through the following formula:

[0027]

[0028]

[0029]

[0030]

[0031] Among them, is the inlet temperature of the -th stage compressor; is the negative pressure adiabatic cooling capacity; is the -th stage compressor outlet temperature; is the inter-stage cooling temperature drop; is the minimum cooler outlet temperature; is the gas adiabatic index; is the -th stage compressor outlet temperature; is the -th stage compressor outlet pressure; is the -th stage compressor polytropic efficiency; is the -th stage compressor outlet gas compressibility factor.

[0032] Furthermore, through the following formula, calculate the -th stage compressor polytropic efficiency:

[0033]

[0034] Among them, is the compressor design flow rate; is the compressor design pressure ratio, with a value range of 1.5 to 4.0.

[0035] Furthermore, through the following formula, adjust the compression power of each stage of the compressor:

[0036]

[0037] Among them, is the -th stage compressor compression power; is the -th stage compressor inlet gas compressibility factor.

[0038] With the above technical solutions, the present invention has the following beneficial effects: In the system disclosed by the present invention, the relationship between the formation gas production and the wellbore negative pressure is no longer merely a passive one. Instead, through real-time monitoring and mathematical model calculation, comprehensive scheduling of key parameters such as the negative pressure intensity, the intake pressure and the outlet pressure of the compressor is achieved. This collaborative optimization enables the wellbore and the formation to avoid bearing additional risks due to the pursuit of extreme negative pressure, and also allows the subsequent multi-stage compressors to avoid rapidly losing efficiency in the case of large flow fluctuations or sudden changes in the pressure ratio. From the description of strategies such as the safe intake pressure, the step-by-step distribution of the outlet pressure, and the inter-stage cooling in the embodiments, it can be seen that the present invention ensures that the compressor cluster can maintain a relatively stable thermodynamic state and pressure increase amplitude when dealing with gas production of different scales by establishing an adaptive compression process. Such an adaptive mechanism greatly alleviates the dependence on the wellhead conditions in multi-stage compression, enabling it to continuously operate in a dynamically changing negative-pressure gas production environment and stably output high-quality gas flow during different production capacity fluctuation cycles. With this full-process dynamic matching, the potential production capacity in the formation can be more fully exerted. Compared with traditional positive-pressure gas production, the pressure gradient under negative pressure is increased, making it easier for low-permeability pores to release the stored gas, greatly increasing the instantaneous gas production rate and delaying the production decline. In the conventional negative-pressure gas production mode, if there is a lack of intelligent compression means, there will be situations such as overloading of compression equipment or frequent start-stop operations along with the gas production peak, wasting energy and accelerating equipment wear. The improvement of the present invention in this regard enables the coordination of enhanced negative pressure and multi-stage compression, forming a smooth and adjustable "production - transmission - utilization" chain from the wellbore to the gas storage and transmission links. Thus, while meeting the high-yield gas production requirements, the system can also control the compression energy consumption at an extremely low level through inter-stage cooling, precise pressure ratio distribution, and real-time power regulation, thereby achieving the dual benefits of high yield and high efficiency. Further, through the calculation and correction of parameters such as the gas compression factor, the critical pressure, and the critical temperature, the system can cope with potential complex effects such as gas volume expansion, density change, and even phase change caused by a significant reduction in the wellbore pressure. Traditional gas production compression methods often have error accumulation when the gas deviates from the ideal state, resulting in inaccurate evaluation of gas production efficiency and deviation in compressor selection, and it is even more impossible to accurately control once entering an unconventional formation environment. However, within the multi-modal fluid compression optimization framework proposed by the present invention, these correction formulas enable the prediction of formation production, negative pressure scheduling, and compression ratio division to closely follow the actual gas behavior, providing an accurate basis for setting the inlet and outlet temperatures and pressures of each stage of the compressor, and also preventing unnecessary heat accumulation and energy loss. BRIEF DESCRIPTION OF THE DRAWINGS

[0039] Figure 1 FIG. is a schematic structural diagram of a negative-pressure gas production device for multi-modal fluid compression optimization provided by an embodiment of the present invention. DETAILED DESCRIPTION OF THE EMBODIMENTS

[0040] All features disclosed in this specification, or steps in all methods or processes disclosed, can be combined in any way, except for mutually exclusive features and / or steps.

[0041] Any feature disclosed in this specification (including any additional claims, abstract) can be replaced by other equivalent or alternative features with similar purposes, unless specifically stated. That is, unless specifically stated, each feature is just an example in a series of equivalent or similar features.

[0042] Example 1: Refer to Figure 1 , a negative pressure gas production device for multi-modal fluid compression optimization, the device includes: a gas collection module, a fluid compression module, and a gas storage and transmission module; the gas collection module is used to make formation gas flow to the collection pipeline through negative pressure and transmit it to the fluid compression module; the fluid compression module includes multiple cascaded compressors, a dynamic pressure optimization control module, and a sensor module; the dynamic pressure optimization control module obtains gas parameters and environmental parameters during underground gas collection through the sensor module, and adjusts the working mode and pressure output of each stage of the compressor in real time, and conveys the compressed gas to the gas storage and transmission module; the gas storage and transmission module is used to store the compressed gas and, in response to a control instruction from a remote end, transmit the compressed gas to the remote end.

[0043] Specifically, during the negative pressure gas production process, the pressure in the wellbore is reduced to a level lower than the original formation pressure, thereby forming a large pressure gradient between the formation and the wellbore. This pressure gradient becomes the main driving force for gas flow. The movement of gas in formation pores is affected by various factors, including permeability, porosity, gas viscosity, pressure gradient, etc. In porous media, the seepage velocity of gas is not only restricted by Darcy's law but also affected by gas compressibility and temperature changes. The present invention accurately predicts the flow behavior of formation gas by establishing a multi-modal fluid seepage model and introducing environmental parameters and gas parameters into the calculation, and makes real-time adjustments under different pressure conditions to ensure the stability of the gas flow rate. Since gas is affected by both viscous force and inertial force during the seepage process, non-linear flow phenomena may occur under high pressure difference conditions. The gas collection module of the present invention combines with the dynamic pressure optimization control module to adjust the negative pressure intensity in real time, avoiding the destruction of the formation structure or the blockage of the gas production channel caused by excessive negative pressure, and at the same time ensuring sufficient pressure gradient to maintain the continuous flow of gas.

[0044] In addition, the gas collection module of the present invention monitors key parameters such as formation pressure, gas density, flow rate, and permeability in real time through a sensor module, and establishes a dynamic feedback system in combination with environmental parameters to achieve intelligent control. Especially when the formation pressure is low or the permeability is small, the system can optimize the gas collection efficiency by adjusting the negative pressure level to avoid reservoir damage caused by excessive negative pressure. During the process of gas production under negative pressure, after the gas enters the collection pipeline, both its pressure and temperature will change. Since the gas enters the low-pressure area from the formation, the expansion effect will cause the temperature to decrease, which may affect the fluidity of the gas and even trigger the formation of hydrates or gas condensation. Therefore, the present invention combines the gas state equation and the thermodynamic model to correct the temperature change of the gas inside the wellbore in real time, and adopts appropriate temperature compensation strategies as needed, such as using heating devices or heat recovery technologies, to prevent the adverse effects of low-temperature effects on gas flow.

[0045] The fluid compression module plays a crucial role in the multi-modal fluid compression optimized negative pressure gas production device of the present invention. It not only has to gradually increase the low-pressure gas flow from the gas collection module to the required final discharge pressure, but also must take into account multiple factors such as energy consumption, equipment operation safety, and gas property changes during this process to ensure the high efficiency and stability of the overall system. A multi-stage series of compressors are installed inside this module. Each stage of the compressor will dynamically adjust its working mode, inlet and outlet pressures, and operating speed according to the real-time data collected by the sensor module during operation. The aim is to make the compression ratio of each stage work within the optimal range, thereby minimizing the energy consumption waste and mechanical wear risks caused by over-compression or under-compression. Since under negative pressure gas production conditions, the gas from the formation often has large pressure differences and temperature gradients, and there are also obvious differences between the temperature of the underground formation and the ambient temperature at the compressor inlet, it is necessary to monitor and control parameters such as the pressure, temperature, density, and flow rate of the gas during multi-stage compression. For this reason, the fluid compression module is equipped with a dedicated dynamic pressure optimization control module, which will determine the range in which the inlet pressure and outlet pressure of each stage should be maintained based on information such as the gas composition, formation gas production rate, gas pressure and temperature provided by the sensors, and taking into account the design parameters and load capacity of each stage of the compressor, while comprehensively managing the heat generated during the compression process.

[0046] To reduce the problem that the rapid temperature rise of the gas under high pressure leads to a decrease in equipment efficiency or adverse changes in gas properties, an intermediate cooling device is often provided between adjacent compressors in this module. Thus, after the first-stage or second-stage compression is completed, the gas is cooled to keep it within a relatively appropriate temperature range when entering the next compression stage, avoiding material stress concentration and additional energy consumption waste caused by high temperature. Meanwhile, the fluid compression module determines the most suitable polytropic compression strategy based on information such as the adiabatic index, molecular weight, and real-time temperature of the gas. By dynamically updating the compression ratio and flow distribution at each stage, the overall power consumption can be kept at a low level on the premise of achieving the established discharge pressure. This process relies on the multi-modal fluid optimization model proposed in the present invention. After performing seepage calculation and gas production rate prediction on the formation gas, the model matches the calculated gas production rate with the intake requirements of each stage of the compressor, and then combines key data such as the gas compression factor, flow parameters, and compressor speed obtained from real-time monitoring to generate a set of optimal control instructions after continuous iterative solution, enabling each stage of the compressor to complete the pressurization task with higher efficiency in a negative-pressure gas production environment. Through this adaptive, multi-parameter coupling algorithm, the present invention can ensure an appropriate intake pressure when the formation pressure is low, prevent excessive gas inhalation and compressor overload, and can also timely increase the flow rate and pressure ratio of each stage of the compressor when the formation gas supply is sufficient, maximizing the gas production efficiency. It is worth mentioning that the fluid compression module and the gas collection module do not operate independently, but are closely linked through means such as pressure detection, temperature detection, and flow detection: when the collection module monitors insufficient formation productivity or fluctuations in wellbore pressure, the compression module will correspondingly reduce the intake pressure or the compression ratio to avoid causing too large a pressure difference to the formation; conversely, when the formation shows high productivity or a significant decrease in gas viscosity, the compression module can increase the working power and operating speed of each stage of the compressor, allowing the gas to be pumped to the subsequent gas storage and transmission modules with higher efficiency. In addition, the present invention also pays special attention to the detection of gas components during the compression process. Since formation gases such as natural gas may condense or precipitate heavy components when the pressure and temperature change, the fluid compression module is linked with the sensor module. Once it detects a tendency of condensation or the possibility of hydrate formation in the gas, it will avoid the formation of the liquid phase by adjusting the intermediate cooling temperature, increasing the outlet temperature of a certain stage, or adding external additives, thereby ensuring the stable operation of the compression system.

[0047] Compared with the existing technologies that solely rely on fixed compression ratios or manual adjustment methods, the fluid compression module of the present invention can achieve adaptive multi-stage pressure distribution and temperature management, significantly reducing the energy consumption and loss risks of the system under different gas production conditions. At the same time, it takes into account the complexity of gas components and makes full use of the inherent advantages of negative pressure gas production to more thoroughly collect the low-permeability gas resources underground. Under such an overall design concept, the fluid compression module not only has the ability of efficient pressurization, but also forms an organic whole that closely cooperates with the gas collection module and the gas storage and transmission module, greatly improving the production capacity and controllability of the entire negative pressure gas production system, and also providing an accurate and flexible operation space for subsequent remote monitoring and intelligent scheduling. Since the real-time gas conditions are constantly monitored and various parameters are dynamically adjusted in combination with the equipment characteristics during this process, this module has successfully overcome the problems such as being easily affected by negative pressure fluctuations in traditional compression methods, the inability to finely control energy consumption, and the difficulty in timely correction after the gas properties change non-linearly. As a result, the present invention can exert its advantages of high efficiency, stability, and flexibility in the actual exploitation of low-permeability formations.

[0048] During the process of negative pressure gas production, due to the limited fluidity of formation gas, the gas production rate often has great uncertainty and may fluctuate significantly due to changes in formation permeability, fluctuations in wellbore pressure, or adjustments in gas production intensity. Therefore, the gas storage and transmission module must have a certain buffering capacity to cope with possible uneven gas supply problems and ensure the stability of subsequent transportation links. At the same time, since the operating state of the compressor is affected by the real-time gas source flow rate, the existence of the gas storage system can also provide a temporary pressure regulation function when the gas production rate fluctuates violently, avoiding situations such as unstable compressor operation due to too low intake pressure or overpressure of the storage unit due to excessive gas supply in a short period. To achieve this goal, the gas storage and transmission module of the present invention adopts a storage and transportation strategy based on dynamic regulation, and the intelligent pressure management system monitors the gas pressure entering the storage unit in real time, and dynamically adjusts the storage pressure in combination with factors such as gas physical property parameters, ambient temperature, and downstream demand, so that it always remains within the optimal working range. Compared with the traditional fixed-pressure gas storage system, the gas storage and transmission module of the present invention can adaptively adjust the gas storage state according to the actual working conditions, improve the adaptability of the system to different load conditions, and significantly reduce the energy consumption losses caused by fluctuations in storage pressure. After the gas enters the storage unit, in order to prevent the influence of temperature and pressure changes on the physical state of the gas, this module also adopts an accurate thermal management system, which monitors the temperature change of the storage environment and adjusts the gas pressure control strategy in a timely manner to prevent gas liquefaction caused by temperature reduction or the reduction of gas density due to temperature increase affecting the transportation efficiency.

[0049] When gas needs to be transported to a remote end, the system will perform intelligent scheduling based on downstream demands, taking into account the remote pressure level, the flow resistance of the transport pipeline, and the remaining capacity of the storage unit to determine the optimal transport time and pressure parameters to ensure the efficiency and stability of the transport process. In addition, the gas storage and transmission module of the present invention has been specifically optimized for the possible pressure losses and pipeline friction losses during the transport process. By optimizing the gas transport path, reducing the roughness of the pipeline inner wall, and adopting a segmented pressurization strategy, the energy losses during the transport process are effectively reduced, and the final transport efficiency of the gas is improved. It should be noted that due to the long-distance transmission of the transport pipeline, it may be interfered by external environmental factors. For example, the gas may undergo thermal expansion or contraction due to changes in the external temperature during long-distance transport, resulting in unstable transport pressure. In extreme cases, it may even cause pipeline blockage due to the formation of hydrates in a low-temperature environment. Therefore, the gas storage and transmission module of the present invention tracks the state of the transported gas in real time through an on-line monitoring system and adjusts the pressure and temperature parameters in the pipeline when necessary to ensure the safety and reliability of the transport process. Compared with traditional storage and transport methods.

[0050] Embodiment 2: The execution process of the dynamic pressure optimization control module specifically includes: establishing a flow model of gas in porous media under negative pressure according to environmental parameters and gas parameters, and calculating the gas production of the formation; according to the gas production of the formation, adjusting the intake pressure of the first-stage compressor to the safe intake pressure in combination with gas parameters, and adjusting the inlet pressure, outlet pressure, inlet temperature, outlet temperature, compression power, and inter-stage cooling temperature drop between adjacent-stage compressors according to the safe intake pressure and the required final discharge pressure.

[0051] Specifically, during the execution of the dynamic pressure optimization control module, first, a flow model of gas in porous media under negative pressure needs to be established, which is the theoretical basis for ensuring the stable operation of the gas production device. The flow of formation gas is affected by various factors such as permeability, porosity, pressure gradient, temperature change, and the physical property parameters of the gas itself. Therefore, it is difficult to accurately describe the gas flow behavior simply by using the classical Darcy's law. The model adopted in the present invention not only considers the influence of permeability on the gas flow rate but also introduces gas viscosity, temperature, compressibility factor, and the motion characteristics of gas molecules to more precisely characterize the flow characteristics of gas in the formation. This flow model can calculate the formation gas production rate in real time and, combined with the data collected by sensors, determine whether the current gas supply capacity is sufficient to support the established compression load. Once the formation gas production rate is determined, the dynamic pressure optimization control module will precisely regulate the intake pressure of the first-stage compressor in combination with gas parameters to ensure that its intake pressure remains within a safe range. The determination of the safe intake pressure is one of the key factors for the stable operation of the system. If the intake pressure is too low, it may lead to insufficient gas intake by the compressor, reducing the overall system processing capacity; while if the intake pressure is too high, it may impose too large a pressure drop on the formation, thereby triggering the risk of formation structure damage or even collapse. Therefore, the present invention calculates the optimal safe intake pressure through mathematical modeling methods, combined with the gas state equation and formation stress analysis, and makes real-time adjustments during the dynamic control process to adapt to the fluctuations of formation pressure and the changes in gas production rate.

[0052] After determining the safe intake pressure of the first-stage compressor, the system further optimizes and calculates the inlet pressure, outlet pressure, temperature change, and compression power of each stage of the compressor according to the requirements of the final discharge pressure. Since the gas experiences a significant temperature rise during the multi-stage compression process, and high temperatures may lead to a decrease in compressor efficiency, changes in gas composition, and even material fatigue damage, the present invention introduces a cooling optimization strategy between compressor stages. By reasonably designing the temperature drop during inter-stage cooling, the inlet temperature of each stage of the compressor is always maintained within an appropriate range. When calculating the outlet pressure of each stage, the control module not only considers the theoretical isentropic compression ratio but also combines the gas compression factor, temperature change, and the polytropic efficiency of the compressor to ensure that the compressor can maintain a high compression efficiency under different operating conditions. In addition, the control module also adjusts the compression power according to the real-time operating state to ensure stable energy transfer between each stage of the compressor and minimize energy loss. Overall, the dynamic pressure optimization control module of the present invention realizes intelligent control of the whole process from formation gas production to multi-stage compression through accurate modeling and real-time optimization and regulation, enabling the gas flow in the entire system to always be in an optimal state. Compared with the traditional fixed-parameter compression system, this module can adaptively adjust the operating state of the compressor and shows higher adaptability and energy efficiency advantages when facing challenges such as unstable formation gas supply, changes in gas physical properties, and fluctuations in environmental conditions.

[0053] Example 3: The environmental parameters include: absolute formation permeability , with a value range of 1 to 100, unit of mD; formation pressure , unit of Pa; formation temperature , unit of K; wellbore perforation area , unit of m²; formation porosity ; formation hydraulic pressure , unit of Pa; formation uniaxial compressive strength , unit of MPa; formation Poisson's ratio ; The gas parameters include: gas dynamic viscosity , unit of Pa·s; gas molecular weight , unit of g / mol; gas critical pressure , unit of MPa; gas critical temperature , unit of K; gas adiabatic index ; gas real-time temperature , unit of K; gas specific heat capacity , unit of kg·K; gas real-time pressure , unit of Pa.

[0054] Specifically, the primary variable of the environmental parameters is the absolute formation permeability, which is an important indicator describing the gas flow ability in the formation pore structure. Its value range is between 1 and 100 mD, where mD (millidarcy) is the standard unit for measuring permeability. When the permeability is high, gas is more likely to flow into the wellbore and the recovery rate is high; while when the permeability is low, gas flow is restricted and the effect of negative pressure gas production is more significant. Therefore, in practical applications, the system needs to dynamically adjust the negative pressure intensity according to the formation permeability to ensure an appropriate pressure gradient so that the formation gas can flow smoothly into the collection pipeline. Another important parameter closely related to permeability is the formation pressure, which is the original pressure of the gas in the formation and determines the driving force for the gas to flow into the wellbore. During the negative pressure gas production process, the pressure in the wellbore is usually reduced to a level lower than the formation pressure, thus forming a sufficient pressure gradient to drive the gas to flow into the collection pipeline. However, if the formation pressure is too low, the system needs to adopt a more precise pressure control strategy to avoid formation structure damage or gas flow stagnation caused by excessive pressure reduction.

[0055] The primary variable of the environmental parameters is the absolute formation permeability, which is an important indicator describing the gas flow ability in the formation pore structure. Its value range is between 1 and 100 mD, where mD (millidarcy) is the standard unit for measuring permeability. When the permeability is high, gas is more likely to flow into the wellbore and the recovery rate is high; while when the permeability is low, gas flow is restricted and the effect of negative pressure gas production is more significant. Therefore, in practical applications, the system needs to dynamically adjust the negative pressure intensity according to the formation permeability to ensure an appropriate pressure gradient so that the formation gas can flow smoothly into the collection pipeline. Another important parameter closely related to permeability is the formation pressure, which is the original pressure of the gas in the formation and determines the driving force for the gas to flow into the wellbore. During the negative pressure gas production process, the pressure in the wellbore is usually reduced to a level lower than the formation pressure, thus forming a sufficient pressure gradient to drive the gas to flow into the collection pipeline. However, if the formation pressure is too low, the system needs to adopt a more precise pressure control strategy to avoid formation structure damage or gas flow stagnation caused by excessive pressure reduction.

[0056] Formation porosity is another key factor affecting gas reserves and flow capacity, which determines the storage space for gas in the formation. Higher porosity means the formation can hold more gas and there is less restriction to gas flow, while lower porosity indicates limited gas storage space and poor fluidity. Therefore, during system optimization, the system needs to comprehensively consider parameters such as porosity, permeability, and pressure to determine the most suitable gas production strategy. The formation hydraulic pressure and the uniaxial compressive strength of the formation jointly determine the stability of the formation and its ability to withstand pressure changes. During negative-pressure gas production, if the wellbore pressure drops too quickly or is too low, it may cause formation collapse or wellbore damage. Therefore, the system needs to monitor these two parameters in real time and calculate the formation stress in combination with the Poisson's ratio to ensure that the gas production process is carried out within a safe range.

[0057] In addition to environmental parameters, the present invention also monitors and optimizes gas parameters in detail to ensure that the state of the gas is always at the best level during collection, compression, and transportation. The dynamic viscosity of the gas is one of the key parameters affecting gas flow resistance. Higher viscosity means greater flow resistance. Therefore, in an environment of high-viscosity gas, the system may need to increase the negative pressure intensity or adjust the gas production rhythm to ensure smooth gas flow. The gas molecular weight affects the density and flow rate of the gas. A larger molecular weight usually means a higher density, and the change in density directly determines the working load of the compressor. Therefore, when performing pressure optimization calculations, the system must consider the influence of the gas molecular weight. The critical pressure and critical temperature of the gas are basic parameters for measuring gas state changes. When approaching the critical state, the physical properties of the gas will change drastically. Therefore, the system needs to monitor the pressure and temperature of the gas in real time to prevent the gas from entering the critical region and affecting the compression efficiency. The adiabatic index of the gas determines the thermodynamic behavior of the gas during compression, which affects the degree of temperature rise of the gas during compression. Therefore, during compressor optimization, this parameter is used to calculate the temperature adjustment strategy for each stage of the compressor. In addition, the real-time temperature and specific heat capacity of the gas determine the heat capacity and heat exchange capacity of the gas. During inter-stage cooling, these parameters are used to calculate the optimal cooling temperature drop to ensure that the gas maintains an appropriate temperature when entering the next stage of the compressor. Finally, the real-time gas pressure is one of the core parameters for the operation of the entire system. It not only affects the gas flow rate and the working state of the compressor, but also directly determines the final transportation pressure and storage conditions. Therefore, the dynamic pressure optimization control module of the present invention continuously monitors the gas pressure and dynamically adjusts the operating state of the system in combination with all environmental and gas parameters to achieve the optimal gas collection, compression, and transportation efficiency.

[0058] Example 4: Calculate the formation gas production using a flow model:

[0059]

[0060] wherein, is the formation gas production rate, with the unit of kg / s; is the gas flow velocity in the porous medium, with the unit of m / s; is the gas density, with the unit of kg / m³.

[0061] Specifically, gas density is an important factor determining gas production, and it is affected by formation pressure, temperature, gas molecular weight, and compressibility factor. Since the negative pressure gas production device enhances the fluidity of formation gas by reducing the pressure in the wellbore, the gas pressure inside the wellbore is usually much lower than the formation pressure, which results in a large pressure change during gas flow, and the gas density changes with the pressure. In the low-pressure state, the gas volume expands and the density decreases, while in the high-pressure state, the gas density increases, thus affecting the mass content per unit volume. The present invention uses the gas state equation to calculate the density to ensure accurate calculation of the gas mass flowing into the wellbore based on real-time monitoring of gas pressure and temperature. Secondly, the flow rate of gas in the formation determines the efficiency of gas flowing into the wellbore. In the negative pressure gas production mode, the pressure in the wellbore is much lower than the formation pressure, forming a pressure gradient converging towards the wellbore, and this gradient becomes the main driving force for gas flow. However, gas does not flow freely in the formation but is affected by formation permeability, pore structure, and flow resistance, so its flow rate is jointly restricted by various factors. The present invention uses the modified Darcy's law to describe the seepage behavior of gas in porous media and modifies it for gas compressibility and temperature changes to ensure the accuracy of flow rate calculation. Since the formation permeability determines the fluidity of gas, in low-permeability gas reservoirs, the flow rate is low, while in high-permeability formations, the flow rate is high. To optimize the effect of negative pressure gas production, the present invention dynamically adjusts the negative pressure intensity in the wellbore by real-time monitoring parameters such as formation pressure, permeability, and gas viscosity, so that the gas flow rate is maintained within an optimal range, which can not only ensure a sufficient gas production rate but also avoid formation damage or pore structure changes caused by too high a flow rate. In addition to the influence of flow rate and density, the wellbore perforation area is also a key factor determining gas production. Wellbore perforation is the main channel for gas to enter the collection pipeline, and its size directly determines the gas flow rate that can pass through per unit time. If the perforation area is too small, even if the pressure gradient of formation gas is large, the restricted flow will still lead to a decrease in gas production rate, while if the perforation area is too large, it may cause too strong local negative pressure and trigger instability of the formation structure. The present invention adopts an accurate perforation area optimization design, enabling the wellbore perforations to be optimally distributed according to formation characteristics, and combining with a dynamic regulation system to timely adjust the negative pressure level during gas production to match the flow characteristics of the perforation area and ensure smooth and efficient gas flow. Finally, formation porosity determines the gas storage capacity in the formation, which reflects the proportion of effective gas space inside the porous medium and thus affects the release rate of gas under negative pressure drive. Higher porosity usually means larger gas reserves and faster flow velocity, while lower porosity may limit the gas production process.In traditional gas production calculation methods, the formation porosity is often assumed to be a fixed value. In contrast, the present invention combines formation structure analysis and real-time monitoring data to establish a dynamic porosity adjustment mechanism, enabling the system to adaptively adjust the rate of negative pressure gas production according to the actual conditions of the formation around the wellbore, preventing formation pore closure or flow channel blockage caused by excessive extraction.

[0062] Example 5: Flow Velocity of Gas in Porous Medium The calculation is performed using the following formula:

[0063]

[0064] Where, is the standard reference pressure, with a value of 101325 Pa; is the standard reference temperature, with a value of 293.15 K; the gas density is calculated using the following formula:

[0065]

[0066] Where, is the universal gas constant, with a value of 8.314 J / (mol·K); is the gas compressibility factor, calculated using the following formula:

[0067] .

[0068] Specifically, first look at the formula describing the gas flow velocity. The most fundamental part is , where represents the formation permeability. A higher value indicates a better interconnectedness of the pores within the formation porous medium, allowing gas to flow more freely through it. And is the viscosity of the gas, reflecting the magnitude of the internal frictional force when the gas is flowing. When is relatively large, the intermolecular forces between gas molecules are more significant, and the flow resistance increases accordingly, resulting in a decrease in the gas seepage velocity. In this case, the negative pressure gas production device may need to maintain a higher pressure gradient to ensure the established gas production rate. Immediately following, represents the pressure gradient, and the negative sign indicates that the gas flows in the direction of decreasing pressure, which is the main "driving force" for promoting gas seepage. The principle of negative pressure gas production is precisely to apply a pressure lower than that of the formation in the wellbore, magnify value, enabling the gas to have sufficient power to flow towards the wellbore, thereby improving the gas production efficiency. However, if the pressure gradient is too large, the formation may face the risk of collapse or particle migration. Therefore, the dynamic pressure optimization control module of the present invention needs to continuously monitor and regulate the negative pressure intensity to achieve a balance between high recovery rate and formation safety.

[0069] In addition, appears to correct the compressibility differences of gases at different absolute pressures. The standard reference pressure is usually taken as 101325 Pa (i.e., one standard atmospheric pressure), while is the actual pressure in the wellbore or local formation. When the pressure in the wellbore is significantly lower than the formation pressure, the value of this correction factor may be relatively large, reflecting the characteristic that the gas volume expands sharply with pressure change at low pressure, and also revealing that when further decreases, the actual contribution of negative-pressure gas production to the gas flow rate increase becomes more obvious. If the formation pressure itself is relatively high, the value will decrease, indicating that there is no significant volume expansion space for the gas relative to the standard state, and negative-pressure gas production needs to be combined with other strategies (such as adjusting formation permeability or wellbore perforation parameters) to maintain a stable gas production rate at this time. Immediately following, this part is the temperature correction factor, which is used to reflect the change in the molecular motion rate of the gas with the increase or decrease of temperature. For an ideal gas, an increase in temperature means an increase in molecular kinetic energy, and thus the seepage velocity will also increase accordingly. If the formation temperature is significantly lower than the reference temperature (usually taken as 293.15 K), the thermal motion of gas molecules weakens, and the flow performance also decreases. Through real-time monitoring and appropriate computational simulation, the present invention can take heat preservation or heating compensation measures in advance under the condition of low temperature to prevent the adverse impact of the flow rate attenuation caused by temperature reduction on the gas production efficiency.

[0070] When the gas flow rate in the formation is known, it is necessary to further calculate its density, because in a negative-pressure gas production device, the gas mass obtained per unit time depends on the product of the flow rate and the density. The calculation formula for gas density is , which is derived from the extended form of the ideal gas state equation, incorporating the correction of the real gas compressibility factor. Here is still the pressure of the gas environment, which complements in the flow rate calculation: when the pressure is higher, the number of gas molecules contained in the same volume is more, and thus the density increases, while negative-pressure gas production makes the wellbore at a lower pressure, so the gas density is relatively low in this area. However, if the original formation pressure is extremely high, even if the wellbore is at negative pressure, it does not affect the high-density characteristics when the gas flows into the wellbore. is the molecular weight of the gas, which is used to distinguish natural gas or mixed gas with different compositions. For example, gas containing more heavy components usually has a larger molecular weight, which will directly lead to an increase in density. The present invention will refresh The value is used to more precisely calculate the density and guide the control of the intake parameters of the compressor. is the universal gas constant, a fixed value commonly used in physics that provides a link between dimensions such as pressure, volume, temperature, and molecular weight. represents the real-time temperature of the gas. As the temperature rises, the molecular motion intensifies, causing the volume to expand and the density to decrease. However, the impact on gas production still needs to be comprehensively evaluated in combination with factors such as flow rate. Sometimes, the increase in temperature leads to a decrease in gas viscosity and an increase in flow rate, which may compensate for the production loss caused by the density decrease.

[0071] Compression factor is crucial for correcting the deviation of real gases from ideal gas characteristics under high pressure or special temperature conditions. If it is ignored and the gas is simply treated as an ideal gas, significant errors may occur in the high-pressure section, resulting in a large difference between the predicted value and the actual gas production situation, thus misleading the control strategy of the negative pressure gas production device. The formula given in the present invention has its core idea that when the current pressure and temperature of the gas approach or exceed the critical point, the intermolecular forces will cause the gas to exhibit obvious non-ideality. The value of usually deviates from 1, and this degree of deviation is closely related to the ratio between the critical pressure and the critical temperature of the gas. If the ratio of the system pressure to the critical pressure is relatively large and the ratio of the current temperature to the critical temperature is relatively small, then

[0072] this part will become more obvious, making the gas compression factor likely to become smaller (usually less than 1), thus further amplifying the density calculation, corresponding to the fact that the intermolecular attraction between gases increases and the volume shrinks under high-pressure conditions. Just because of this, when the negative pressure gas production device controls the pressure difference between the formation and the wellbore, it needs to pay special attention to this non-ideal effect to avoid local condensation or phase change in the formation pores due to excessive extraction in the high-pressure area, which will have an adverse impact on gas production efficiency and reservoir integrity.

[0072] Example 6: Calculate the safe intake pressure through the following formula:

[0073]

[0074]

[0075] where is the critical pressure for formation collapse; is the safe intake pressure, and the intake pressure of the first-stage compressor is adjusted to ; is the safety margin, with a value range of 50 to 100 and the unit of kPa; is the cross-sectional area of the intake pipe, in m²; Let be the inlet pressure of the -th stage compressor. For , it is of the intake pressure of the first-stage compressor. For , it is the outlet pressure of the previous stage minus the pipeline pressure drop.

[0076] Specifically, in the multi-modal fluid compression optimized negative pressure gas production device of the present invention, to ensure that the formation can maintain a high gas flow efficiency during gas production and will not cause safety hazards such as collapse, sand grain migration or wellbore instability due to excessive negative pressure during gas production, it is necessary to finely control the intake pressure of the first-stage compressor and set a reasonable pressure safety boundary accordingly. For this reason, this embodiment gives a set of formulas including dual constraints of formation mechanics and fluid dynamics for the safe intake pressure, so as to achieve the best compromise between formation pressure and negative pressure gas production. In the formula, first, the critical formation collapse pressure is calculated to evaluate the stability of the wellbore under negative pressure conditions. Specifically, it is obtained by subtracting from the formation hydraulic pressure . This means that on the basis of the hydraulic pressure of the formation, the combined effects of the uniaxial compressive strength and the formation Poisson's ratio are further considered. When the effective stress applied externally exceeds this threshold, the formation is extremely likely to undergo irreversible deformation or even collapse. The Poisson's ratio represents the ratio of the lateral deformation to the longitudinal deformation of the formation material under compression. If is relatively large, the formation is more likely to expand or deform laterally when compressed, and thus the critical collapse pressure is relatively low, and vice versa. Since negative pressure gas production needs to maintain a pressure lower than the formation in the wellbore to enhance gas flow, this requires that after estimating , a certain safety margin is left for the system, so as to prevent the formation from working near the limit critical for a long time and causing safety risks. Based on this, the sum of the critical formation collapse pressure and the safety margin is regarded as the first candidate intake pressure. On the other hand, the supply capacity of the gas itself also needs to be considered, that is, the formation gas production is combined with the molecular weight of the gas , the real-time temperature and the universal gas constant to calculate the minimum pressure required to maintain a specific flow rate. If the negative pressure is too large, although the flow rate can be increased, the risk of formation instability will also increase; if the negative pressure is insufficient, the flow rate cannot meet the intake requirements of the subsequent compressor.

[0077] In the formula, It stems from the analysis of gas flow and cross-sectional flux: when the gas production mass flow rate is fixed, to maintain a high flow rate, it is necessary to ensure that the inlet velocity and density are within a reasonable range, which is closely related to the molecular weight, temperature, gas constant, and the cross-sectional area of the inlet pipeline . The larger this item is, the higher the inlet pressure may be required to support sufficient conveying capacity. At the same time, to correct the influence of the actual gas in the formation deviating from the ideal state, a compression factor is introduced into the formula, which plays a role in correcting the compressibility of real gases in the denominator: when , the actual compressibility of the gas is higher than that of the ideal gas, and it is easy to show the molecular attraction effect in the high-pressure area; while when , it indicates that the molecular repulsion or other factors of the gas lead to the difference from the ideal gas model. If these phenomena are not considered, it will cause large errors in high-pressure or high-flow environments. Finally, the higher one of the two in the formula

[0078] is selected as the inlet pressure of the first-stage compressor , so as to ensure that even when the maximum gas production demand occurs, the system will not pull the wellbore pressure too low, so as not to exceed the collapse critical point of the formation. In this way, on the one hand, the formation can obtain a sufficiently large negative pressure driving force to accelerate gas seepage and improve the recovery rate; on the other hand, it provides a certain pressure redundancy for formation damage and reduces the potential threat to wellbore stability. For subsequent-stage compressors, if there is a pipeline pressure drop, the outlet pressure of the previous stage minus the pipeline pressure drop is used as the inlet pressure of the next stage to ensure that the overall flow scheme of each stage of the compressor can be connected in series at the beginning of the design. The dynamic pressure optimization control module of the present invention will combine real-time monitoring data of the formation, such as the change of porosity over time or gas production intensity, formation deformation monitoring, data provided by flow and pressure sensors, etc., and continuously correct the rationality. Once it is detected that the formation pressure continues to decay or local loosening occurs, it is necessary to promptly increase the wellbore pressure to avoid excessive negative pressure; if it is observed that the formation productivity is still sufficient and the pore structure has not changed significantly, the wellbore pressure can be appropriately reduced to maintain a higher recovery rate. In this way, negative pressure gas production and formation safety are taken into account under the balance control of the overall system, providing a stable inlet gas source for the steady operation of subsequent multi-stage compressors, and enabling the entire negative pressure gas production device to exhibit more efficient and safe performance in complex geological environments such as low-permeability gas reservoirs and shale gas reservoirs. It is worth mentioning that the value range of is between 50 and 100 kPa, which not only takes into account the variable formation mechanical characteristics but also provides sufficient operation adaptability for different types of compressors.

[0079] Example 7: Adjust the outlet pressure of each stage of the compressor according to the following formula:

[0080]

[0081] where is the gas compression factor of the th stage of the compressor; is the gas compression factor of the first stage of the compressor; is the final discharge pressure; is the total number of stages of the compressor; is the th stage of the compressor outlet pressure.

[0082] Specifically, in the formula, an exponential term in the form of can be seen. Here represents the final discharge pressure, that is, the target pressure that the system needs to reach after completing all compression stages; is the intake pressure of the first stage of the compressor, which is jointly determined by the negative pressure gas sampling strategy and the safe intake boundary. In the exponent, reflects that after dividing the compression process into basic stages, the compression ratio share that the th stage of the compressor should bear: when , it is equivalent to just starting the compression, and only obtaining the th power of the total compression ratio; when , it means that all compression stages are completed, and the exponential term in the formula becomes , which exactly reaches the final discharge pressure. In an ideal situation, if the properties of the gas do not change significantly during the compression process of each stage, or can be approximately regarded as an ideal gas, then only by distributing the overall compression ratio of to each stage according to such an exponent, the compressor group can work under a relatively balanced load, avoiding a large increase in mechanical energy consumption, exhaust temperature or equipment wear caused by an excessive single-stage compression ratio, and also avoiding investment waste and system complexity caused by splitting a too small compression ratio into many stages.

[0083] However, in actual working conditions, the degree to which the gas deviates from the ideal gas state cannot be ignored. Especially in the negative pressure gas sampling mode, the intake pressure in the wellbore is much lower than the conventional conditions, and the target discharge pressure in the subsequent compression process may be quite high, resulting in a large difference in the pressure ranges of the first few stages and the last few stages of the compressor, and the temperature change will also be quite drastic. To solve this problem, the present invention multiplies the end of the formula by , where is the gas compression factor of the th stage of the compressor, and represents the gas compressibility factor at the first stage. The physical meaning of this correction term is that if the gas processed at the stage shows more significant non-ideality compared to the gas processed at the first stage (which means ), then appropriate adjustments need to be made in the compression ratio distribution so that the actual outlet pressure at the stage is slightly higher or lower, to compensate for the impact of the gas deviating from the ideal state. Under high pressure or relatively high temperature conditions, real gases may exhibit behaviors significantly different from ideal gases. For example, the influence of intermolecular attraction or repulsion is more significant, ultimately resulting in significant differences between parameters such as the gas compression ratio, exhaust temperature, or specific volume and the ideal formula. If a simple equal ratio exponent distribution strategy is still used, then in the subsequent compression stages, the temperature rise or volume change of the gas may far exceed expectations, not only causing energy waste but also threatening the safe operation of the compression equipment. Therefore, the here is an adaptive correction that allows the actual outlet pressure of the subsequent stages to be finely adjusted according to the change in gas physical properties, ensuring that the stage can boost the gas appropriately and also avoid the situation where the load of a certain stage suddenly increases or decreases.

[0084] In actual operation, the dynamic pressure optimization control module will calculate the instantaneous compressibility factor of the gas based on the data collected by sensors (including the temperature, pressure, flow rate of the gas at the inlet of each stage, and the same type of information at the outlet of each stage). If the system detects that the gas composition or pressure state of the stage compressor has deviated significantly from that of the first stage, it may be because the temperature of the gas has risen after several stages of compression and the intermolecular interaction has increased, resulting in being significantly lower compared to . At this time, it is necessary to automatically correct the outlet pressure of the stage through this formula, making it slightly higher than the original equal ratio distribution value, so as to allocate more compression amount to avoid excessive boosting of the subsequent stages, resulting in a sharp increase in energy consumption or temperature rise. On the contrary, if the compressibility factor is greater than its value at the first stage in the subsequent stages, it means that the non-ideality of the gas has weakened, or enough heat has been released during the intermediate cooling process, and the gas is closer to the ideal state. Then the compression system can transfer the "extra" compression ratio to the subsequent stages, increasing the compression amount of the middle and later stages and appropriately reducing the load of the stage, so that the entire system still maintains the original designed total energy input level. In addition, this corrective exponent distribution also forms a relatively balanced temperature gradient and pressure gradient between the first few stages and the last few stages, without obvious "bottleneck stage" phenomena, and also helps to disperse the compression heat to multiple inter-stage coolers for processing, improving the overall thermal management efficiency.

[0085] In the past, in multistage compression, a very simple fixed compression ratio distribution principle was usually adopted, or the compression ratios of different stages were distributed based on empirical data, ignoring the thermodynamic property differences of the gas between different stages. This often led to some stages overloading or the operating points of individual stages deviating too much from the optimal efficiency range. The formula of the present invention introduces correction on the basis of equal ratio distribution and adapts to the characteristics of lower intake pressure during negative pressure gas production, thus realizing the real-time distribution optimization of the load between compressor units. At the same time, since the present invention also monitors various operating indicators such as the outlet temperature, flow rate, and compression power consumption of each stage, the outlet pressure regulation formula and the overall energy optimization model can be coupled together. When it is detected that the energy utilization rate of a certain compression stage is low or the output temperature is too high, the outlet pressure target of the subsequent stage can be automatically adjusted through the control module to alleviate problems such as local heat load concentration and mechanical stress concentration, and finally improve the comprehensive performance of the entire compression system under different working conditions.

[0086] It should be noted that in this formula only describes the piecewise exponential relationship of the compression ratio, while acts as a "correction factor" that takes into account the characteristics of real gases. When the gas properties remain approximately unchanged or the intermolecular interactions are not significant, will be relatively close to 1, that is, at this time the formula basically returns to the ideal equal ratio distribution model, making the pressure steps of each stage of the compressor increase in equal proportion. On the contrary, once the gas deviates from the ideal range, will cause a "small tilt" in this equal ratio distribution. Some stages will appropriately increase the compression amount, while some stages will relatively reduce the compression amount, ultimately meeting the accurate demand for the total discharge pressure. Since the present invention is often adapted to complex working conditions such as low-permeability formations or unconventional natural gas, the gas is affected by temperature, composition, and permeability conditions in the formation and may show a large deviation from the ideal state. Therefore, this correction term can well offset the uncertainty brought by the real characteristics of the gas, enabling multistage compression to still maintain the expected efficiency range and avoid frequent manual intervention.

[0087] Finally, on the premise of negative pressure gas production, the present invention embeds this formula into the dynamic pressure optimization control module and forms a closed-loop regulation in cooperation with formation pressure, wellbore negative pressure, real-time flow rate, inter-stage cooler temperature regulation, and other safety restrictions. Whenever the formation gas production fluctuates or the wellbore pressure level changes due to external factors, the outlet pressure of each stage will be recalculated accordingly and updated according to the gas state at any time . In this process, it is possible to quickly increase the first The pressure output of each stage meets the intake air requirements of the subsequent stage. It can also reduce the compression load of the corresponding stage when the gas extraction volume decreases, thereby reducing the overall energy consumption of the system. In this way, the coupled operation of negative-pressure gas extraction and multi-stage compression no longer depends on the fixed ratio regulation set artificially, but becomes more flexible and adaptable, greatly improving the overall efficiency of natural gas extraction and subsequent processing, and also providing an advanced solution for the development and utilization of unconventional oil and gas resources to maintain high efficiency in complex geological and operating environments.

[0088] Example 8: Adjust the inlet temperature, outlet temperature, and inter-stage cooling temperature drop of each stage of the compressor through the following formula:

[0089]

[0090]

[0091]

[0092]

[0093] Among them, is the inlet temperature of the -th stage compressor; is the negative-pressure adiabatic temperature drop; is the outlet temperature of the -th stage compressor; is the inter-stage cooling temperature drop; is the lowest outlet temperature of the cooler; is the gas adiabatic index; is the outlet temperature of the -th stage compressor; is the -th stage compressor outlet pressure; is the -th stage compressor polytropic efficiency; is the -th stage compressor outlet gas compressibility factor.

[0094] Specifically, in the negative-pressure gas extraction device with multi-modal fluid compression optimization of the present invention, in order to give full play to the working efficiency of the multi-stage compressor in different pressure sections and ensure that the gas can maintain an appropriate temperature range during the coupled process of negative-pressure gas extraction and multi-stage compression, it is necessary to accurately control the inlet and outlet temperatures of each stage of the compressor. Based on this, the present invention proposes a set of formulas for dynamically adjusting the temperature and cooling strategy to effectively control the compression heat accumulation and the resulting energy loss and material load while maintaining the compression efficiency. In these formulas, the first thing to focus on is the inlet temperature of each stage of the compressor , for the first-stage compressor, considering the negative-pressure adiabatic cooling phenomenon in the wellbore or pipeline, the original gas temperature is subtracted by a term . This temperature drop reflects the adiabatic cooling effect generated when the gas expands in a negative-pressure environment. Since the greater the negative pressure, the more obvious the adiabatic expansion of the gas and the greater the temperature drop, the here is obtained by estimating the relationship between the adiabatic index of the gas, the formation pressure, and the wellbore negative pressure, so that the gas temperature entering the first-stage compressor is closer to the actual working conditions. For any stage of the compressor, the inlet temperature comes from the outlet temperature of the previous-stage compressor , and then subtracted by a term to represent the result after the inter-stage cooler releases heat from the gas. In this way, the gas at the stage can be pre-cooled before entering the compressor, reducing the load on the compressor and the additional heat accumulation when the gas is continuously compressed.

[0095] In the formula, this term is used to describe the inter-stage cooling temperature drop between different compression stages, and its magnitude depends on the outlet temperature of the gas in the previous stage , the lowest outlet temperature of the cooler , and the adiabatic expansion effect of the gas during the cooling process from to . Specifically, it first cools the gas from a high temperature to the that the equipment can stably output, and then combines the thermodynamic constraint of the adiabatic index of the gas during the expansion process, and subtracts this part of to represent the additional heat released when expanding from a higher pressure to a lower pressure, thus making a further correction to the cooling temperature drop. The reason for this design is that after each stage of compression, if the temperature is too high, the viscosity and density of the gas will change unfavorably with the increase in temperature, and the material will also face more stress and fatigue risks under high-temperature conditions. Therefore, it is necessary to efficiently remove part of the heat through the intermediate cooler. However, if the cooling is excessive, it may also lead to condensation or hydrate formation, thus affecting gas flow or the safe operation of the equipment. Through this formula, a compromise can be made appropriately according to the current pressure difference, gas properties, and equipment cooling capacity in practical applications, so that the gas can avoid thermal damage and will not be over-cooled to affect subsequent flow.

[0096] When calculating the outlet temperature of a certain stage of the compressor, the adiabatic index , the polytropic efficiency , and the pressure ratio of the gas are introduced into the formula, and there is also a term , which is used to correct the deviation between real gas and ideal gas. When the compressor performs adiabatic compression, if the energy loss in the compression process is ignored, the gas can be regarded as being subjected to However, in actual working conditions, various irreversible factors will reduce the efficiency of the compressor, so the present invention uses variable efficiency Characterize the actual deviations in these thermodynamic processes to more accurately predict the gas temperature rise. The higher the variable efficiency, the smaller the temperature rise of the compressor at the same pressure ratio and the more efficient the energy utilization; if the efficiency is low, the same pressure ratio will lead to a significant increase in gas temperature. At the same time, It is further shown that when the gas deviates from the ideal gas model, its temperature rise during compression will also differ from the ideal calculated value. The gas deviation at the exit of the first stage is more serious than that of the first stage, for example, the gas has been compressed and heated by the previous stages. compared to There will be a significant reduction, indicating that the intermolecular interaction increases and the gas compressibility increases, so the actual temperature rise may be more drastic than the "ideal state". Through this part of the correction, when the sum of the multi-stage compression remains fixed, adaptive space can be left for the specific thermodynamic changes of each compression process, and the dynamic pressure optimization control module can fine-tune the outlet temperature target at any time according to the change of gas state.

[0097] In this formula It is called the gas adiabatic index, which is an important parameter to measure the relationship between the pressure and volume change of a gas in a reversible adiabatic process. For common natural gas media, Most of them are between 1.25 and 1.4, and the specific value depends on the composition and temperature and pressure conditions. The value may deviate slightly, thus affecting the temperature rise law during compression. , and The coupling of multiple factors makes the temperature control of multi-stage compression more flexible and adaptable. In this way, if an abnormal temperature rise or pressure ratio imbalance occurs in a certain stage, the system can respond in time to maintain the outlet temperature of that stage within a safe and controllable range, and to a certain extent alleviate the energy consumption imbalance and material aging caused by excessive local temperature.

[0098] As for It represents the negative pressure adiabatic cooling amount. Its calculation idea is that when the formation gas is pumped into the wellbore, since the wellbore pressure is significantly lower than the formation pressure, a significant pressure drop is generated between the formation and the wellbore, and the gas expansion potential energy is released, which will cause the gas temperature to drop. control, and also depends on the initial formation temperature, pressure, and the actual negative pressure level reached in the wellbore. If the formation pressure is very high at this time while the wellbore maintains a very low pressure, the cooling effect generated by the gas diffusing from the high pressure to the low pressure area is more significant. In this case, for the first-stage compressor, the inlet temperature will decrease more significantly. However, if the pressure difference between the wellbore and the formation is limited, or the intensity of gas production by negative pressure is relatively weak, the gas expansion is not sufficient enough, it will not be very large. The present invention introduces it into the setting of the inlet temperature of the first-stage compressor, which can avoid overestimating the inlet temperature, and thus make the operation and energy consumption analysis of the compressor more in line with the actual situation.

[0099] The application background of the above series of temperature adjustment formulas is that the formations faced by the present invention often have low permeability, and negative pressure gas production needs to be adopted to strengthen gas flow. At the same time, multi-stage compression is required to lift the relatively low-pressure gas flow in the wellbore to a higher pressure in order to meet the transportation requirements or subsequent processing requirements. Heat accumulation is inevitably brought about by multi-stage compression. Without reasonable inter-stage cooling, the gas temperature will increase layer by layer, resulting in an extremely high outlet temperature at the last stage, which not only wastes energy but also makes the equipment operate under high-temperature load for a long time, accelerating component wear and even endangering production safety. On the contrary, through the dynamic temperature control strategy of the present invention, not only can the excess heat be removed as much as possible in the inter-stage cooler, but also each stage of the compressor can work in a relatively ideal temperature range, maximizing the compression efficiency and reducing energy consumption. At the same time, these formulas also fully consider the prior influence of negative pressure gas production on the inlet-side temperature of the gas, including the adiabatic temperature drop caused by the drawdown of the formation pressure, so that the final multi-stage compression process can start at a lower temperature from the beginning, laying a foundation for reducing the subsequent heat load.

[0100] Example 9: Calculate the polytropic efficiency of the stage compressor through the following formula:

[0101]

[0102] where, is the designed flow rate of the compressor; is the designed pressure ratio of the compressor, and the value range is from 1.5 to 4.0.

[0103] Specifically, this formula gives the relationship between the polytropic efficiency of the stage compressor and the deviation of the gas production flow rate and pressure ratio. Among them, 0.85 is used as the reference efficiency value, which reflects the upper limit of the polytropic efficiency that can be achieved when the machine operates ideally under the design conditions. And when the actual working conditions deviate more from the design parameters, the efficiency will decrease accordingly. Among them, It refers to the "nominal flow rate" targeted by the compressor during the design phase. It is usually the optimal operating range determined by a large amount of experimental data or equipment specifications under certain pressure, temperature and gas composition conditions. If the flow rate exceeds the design value for a long time, it means that the total amount of gas that the compressor has to handle has increased significantly, which may easily lead to increased energy consumption, additional friction loss or increased heat load inside the compressor, so the efficiency will be reduced. When the gas output is lower than the design value, although the small flow rate will not directly cause serious overload, the compressor often cannot maintain the ideal working point in the low flow area, and will also lose some efficiency due to the mismatch of internal fluid dynamics, so it will also lead to corresponding deductions.

[0104] In addition to the flow deviation affecting the variable efficiency, is the actual value of the pressure ratio close to the design pressure ratio? In the negative pressure gas extraction device of the present invention, since the pressure in the wellbore is often lower than the normal working condition, and the gas needs to be raised to a certain discharge pressure later, If the actual pressure ratio of the compressor is too different from the preset design pressure ratio, the internal impeller flow path, seal design and thermodynamic characteristics may not work within the optimal range, resulting in a significant decrease in efficiency. The system will add a proportional deduction item to the pressure ratio deviation, which will introduce the influence of pressure ratio deviation into the calculation of variable efficiency. When the system detects that the larger the ratio is, the farther the actual pressure ratio of the compressor is from the ideal design point. More efficiency deductions will be added to reflect the poor operation of the equipment and the increase in energy loss. For example, if the design pressure ratio is around 2.5, and the pressure ratio is 2.5 under negative pressure gas production conditions, the system will add a proportional deduction item to the pressure ratio deviation. The inlet pressure of the first stage is lower than originally thought, or the outlet pressure is pulled higher to meet the pressure increase demand of the next stage, so that the actual pressure ratio reaches 3.2 or even greater. Such a deviation exceeds the design range, and it is very likely to cause excessive power consumption or thermal management imbalance when matching gas flow, speed and temperature, and ultimately reduce the actual efficiency of the compression process. Based on the same principle, when the actual pressure ratio is too much lower than the design value, the efficiency will also be reduced because the impeller and diffuser structure do not fully utilize the hard-earned pressure head.

[0105] The coefficient of 0.05 used in the formula actually represents the "penalty intensity" of flow deviation and pressure ratio deviation on variable efficiency, and is an empirical value range determined by the present invention based on a large number of numerical simulations and experimental verifications. If these deviations are very significant, the efficiency may drop further from 0.85, and the final result may even fall below 0.7. This urges the system to minimize the deviation from the design point during real-time regulation, or to dispatch other parallel compressors to share excessive flow when necessary, to avoid a single device operating in a non-design range for a long time. At the same time, the design pressure ratio It is usually set between 1.5 and 4.0, which is a range determined according to the compressor model and the oil and gas field transportation requirements. It should not only meet the ability to deliver gas to the required pressure in the middle and later stages, but also take into account the limitations of the compressor impeller structure, the power of the transmission shaft, and the safety margin. If the intake pressure generated during the negative pressure gas production process is extremely low, or the discharge pressure requirement is much higher than the common value, the system will use a multi-stage or parallel method to share the overall pressure ratio, so that each compressor can match its relatively optimal design pressure ratio; assuming that a single compressor is forced to bear too high a pressure ratio, a large deduction will be obtained in this efficiency calculation, prompting the control module to make corresponding strategy adjustments, such as adding inter-stage cooling, changing the speed, or introducing additional compensation means to relieve the over-standard load of a single device.

[0106] The reason why the present invention uses such a formula to express the polytropic efficiency and subtracts it from the base value of 0.85 is mainly to give an approximate estimate that is convenient for real-time calculation and can reflect the actual working condition fluctuations in the negative pressure gas production environment. For each stage of the compressor, if the actual gas production volume it processes exactly matches the designed flow rate and the pressure ratio does not deviate from the pre-conceived value, then the compressor can be relatively close to the efficiency upper limit of 0.85; on the contrary, if the current working condition deviates significantly in terms of flow rate or pressure ratio, it means that it is moving away from the optimal operating point, and the efficiency is correspondingly reduced. The present invention uses an automated monitoring and control algorithm to constantly check the changes. Once it is found that the efficiency of individual stages continues to decline or fluctuate greatly, it will attempt to adjust the wellbore negative pressure, the outlet pressure of the downstream compression stage, and the inlet flow distribution of the compressor, so that the overall system can obtain the maximum gas production with the minimum energy consumption. Under unconventional formations or low permeability conditions, with the change of the formation gas supply capacity and the increase or decrease of the negative pressure intensity, it is very likely that each stage of the compressor will experience different degrees of deviation. Therefore, by continuously updating the polytropic efficiency in combination with this formula, it can provide a more accurate basis for subsequent thermal management, power distribution, and cooling control, enabling the entire device to maintain a steady and efficient operation at all times.

[0107] Example 10: Adjust the compression power of each stage of the compressor through the following formula:

[0108]

[0109] Wherein, is the compression power of the -th stage compressor; is the gas compression factor at the inlet of the -th stage compressor.

[0110] Specifically, it can be seen from this formula that Such an item comprehensively describes the most basic energy input required for gas compression from aspects such as mass flow rate, gas molecular weight, universal gas constant, inlet temperature and compressor variable efficiency. Its meaning is that if the actual gas production of the formation is is much higher than the design value, then under the same inlet and outlet pressure, The compressor must process a larger mass flow rate of gas, and the power consumption will naturally increase; if the gas output is small, even if the pressure ratio remains unchanged, the energy consumption of this part will be reduced accordingly. The larger the value, the more mass the gas contains per unit volume or per unit flow rate. The compressor needs to do more work on the molecules to achieve the same pressure ratio, which leads to an increase in power. The pressure, temperature, volume and molecular weight are unified in one equation, so that the calculation can be applied to different types of natural gas or mixed gas. When the compressor is It will affect the average kinetic energy and specific volume of gas molecules. When the temperature is high, the molecular motion is more intense. Although the density may be slightly reduced, the input work required by the compressor will still increase within a certain range. This part is also closely related to the mechanical characteristics and heat dissipation capacity of the compressor itself. , which describes the loss caused by irreversible factors in the actual operation of the compressor of this level. If the compression process is far away from the ideal isentropic or isothermal curve, or the equipment operating conditions are not in the optimal range, such as the flow rate and pressure ratio deviate greatly from the design value, it will lead to a decrease in efficiency, thereby increasing the power required for the unit mass of gas to be compressed. Combined with the existing multi-variable efficiency calculation model in the present invention, this part can be quantitatively estimated, and the energy consumption caused by the deviation of flow rate and pressure ratio can be reflected in the power calculation, so as to make corrections in subsequent optimization decisions.

[0111] There is another term in the formula , which is part of the thermodynamics of the energy consumption of adiabatic or polytropic compression of a gas. If the gas is theoretically reversibly adiabatically compressed, the gas temperature rises without dissipating heat to the outside world, then the required work can be written as a similar expression, using As an adiabatic index, it reflects the influence of gas molecular freedom and heat capacity ratio. When the pressure is increased, the gas is compressed more tightly, and the work required will increase significantly. When the gas flows between multi-stage compressors, it will also go through inter-stage cooling and thermal management, which will have an additional impact on the final temperature and phase state. However, the work provided by the compressor itself mainly depends on the pressure change and the adiabatic index. A larger value indicates that the gas is closer to the adiabatic properties of an ideal monatomic or diatomic molecule, and the temperature rises faster when compressed, and the power consumption is more significant. being on the small side indicates that the molecular vibration mode or heat capacity characteristics of the gas are different, and the temperature rise is not so drastic. In the formula, This directly reflects the relative magnitude of the work required for the gas under ideal conditions without considering additional losses after a certain pressure ratio occurs. Finally, is used as a coefficient adjustment, that is, to quantify the enthalpy change during the compression process. If it is further considered that the gas produced from some low-permeability or unconventional formations contains heavy hydrocarbons or impurities, or the inlet and outlet pressures and formation negative pressure fluctuate frequently, it will also be reflected by the dynamic correction and the linkage of the aforementioned mass flow term.

[0112] In order to enable the formula to have an adaptive ability in the environment of negative pressure gas production and multistage compression, the dynamic pressure optimization control module of the present invention continuously collects data such as gas flow rate, temperature, inlet and outlet pressures, compressor speed, working power, etc., and calculates the value and of each stage in real time. Once it is found that the increase in gas production or the decrease in wellbore pressure leads to an increase in the pressure ratio, it will trigger a corresponding increase in power. If it is detected that the power of a certain stage of the compressor continues to climb and approaches the equipment safety limit, the system will disperse the pressure burden by means of adjusting the inter-stage cooling capacity, adjusting the next-stage pressure ratio or changing the opening of the inlet control valve, etc., to avoid overloading of a single-stage compressor. In the case of attenuation of formation gas supply or weakening of wellbore negative pressure, the formula will also automatically obtain a lower power demand, so that the compressor can avoid doing extra work under low-load conditions and achieve the purpose of energy saving. In addition, since often changes slightly with temperature, gas composition and pressure, especially in high-temperature and high-pressure working conditions or natural gas environments containing multiple components, by measuring the compressibility factor and specific heat capacity of the gas in real time, it can be dynamically updated to keep the formula accurately depicting the energy consumption. When the wellbore negative pressure is very strong, while the formation gas rushes into the wellbore with a large pressure gradient, and at the same time has to experience a significant pressure increase process in the multistage compressor, this large range of temperature and pressure changes is likely to cause the deviation of each stage of the compression process from the ideal model. At this time, through continuous monitoring and feedback correction of the present invention, the polytropic efficiency and gas heat capacity ratio in the formula can accurately reflect the actual state, ensuring that the calculation of the entire compression power has sufficient timeliness and accuracy.

[0113] Although the specific implementation manners of the present invention are described above, those skilled in the art should understand that these specific implementation manners are only examples. Without departing from the principles and essence of the present invention, those skilled in the art can make various omissions, substitutions and changes to the details of the above methods and systems. For example, combining the above method steps, so as to perform substantially the same function according to the substantially same method to achieve the substantially same result belongs to the scope of the present invention. Therefore, the scope of the present invention is only defined by the appended claims.

Claims

1. A negative pressure gas production device with optimized multimodal fluid compression, characterized in that, It includes a gas collection module, a fluid compression module, and a gas storage and transmission module; the gas collection module is used to make formation gas flow to the collection pipeline through negative pressure and transmit it to the fluid compression module; The fluid compression module includes multiple cascaded compressors, a dynamic pressure optimization control module, and a sensor module; The dynamic pressure optimization control module obtains gas parameters and environmental parameters during underground gas collection through the sensor module, and adjusts the working mode and pressure output of each stage of the compressor in real time, and conveys the compressed gas to the gas storage and transmission module; The gas storage and transmission module is used to store the compressed gas and transmit the compressed gas to the remote end in response to a control instruction from the remote end; The execution process of the dynamic pressure optimization control module specifically includes: establishing a flow model of gas in porous media under negative pressure conditions according to environmental parameters and gas parameters, and calculating the formation gas production; according to the formation gas production, adjusting the intake pressure of the first-stage compressor to the safe intake pressure in combination with gas parameters, and according to the safe intake pressure and the required final discharge pressure, adjusting the inlet pressure, outlet pressure, inlet temperature, outlet temperature, compression power of each stage of the compressor, and the inter-stage cooling temperature drop between adjacent stages of compressors; Calculate the safe intake pressure through the following formula: Among them, is the critical pressure for formation collapse; is the safe intake pressure, and the intake pressure of the first-stage compressor is adjusted to ; is the safety margin, with a value range of 50 to 100, and the unit is kPa; is the cross-sectional area of the intake pipeline, and the unit is m²; Let be the inlet pressure of the -th stage compressor. For , it is of the intake pressure of the first-stage compressor. For , it is the outlet pressure of the previous stage minus the pipeline pressure drop; is the formation hydraulic pressure, and the unit is Pa; is the uniaxial compressive strength of the formation, and the unit is MPa; is the Poisson's ratio of the formation; is the gas production rate of the formation, and the unit is kg / s; is the universal gas constant, with a value of 8.314 J / (mol·K); is the real-time temperature of the gas, and the unit is K; is the molecular weight of the gas, and the unit is g / mol; is the gas compressibility factor.

2. The negative pressure gas production device for multi-modal fluid compression optimization according to claim 1, characterized in that, The environmental parameters include the absolute formation permeability , with a value range of 1 to 100, and the unit is mD; the formation pressure , with the unit of Pa; the formation temperature , with the unit of K; the wellbore perforation area , with the unit of m²; the formation porosity ; the formation hydraulic pressure , with the unit of Pa; the uniaxial compressive strength of the formation , with the unit of MPa; the Poisson's ratio of the formation ; the gas parameters include the gas dynamic viscosity , with the unit of Pa·s; the gas molecular weight , with the unit of g / mol; the gas critical pressure , with the unit of MPa; the gas critical temperature , with the unit of K; the gas adiabatic index ; the real-time gas temperature , with the unit of K; the gas specific heat capacity , with the unit of kg·K; the real-time gas pressure , with the unit of Pa.

3. The negative pressure gas production device for multimodal fluid compression optimization according to claim 2, wherein Calculate the formation gas production using the flow model: Among them, is the formation gas production rate, with the unit of kg / s; is the gas flow velocity in the porous medium, with the unit of m / s; is the gas density, with the unit of kg / m³.

4. The negative pressure gas production device with optimized multimodal fluid compression according to claim 3, characterized in that, Flow rate of gas in porous medium It is calculated using the following formula: Among them, is the standard reference pressure, with a value of 101325 Pa; is the standard reference temperature, with a value of 293.15 K; is the pressure gradient; is the formation permeability; gas density is calculated using the following formula: Among them, is the universal gas constant, with a value of 8.314 J / (mol·K); is the gas compressibility factor, which is calculated using the following formula: 。 5. The negative pressure gas production device for multi-modal fluid compression optimization according to claim 4, characterized in that, Adjust the outlet pressure of each stage of the compressor through the following formula: Among them, is the gas compression factor of the -th stage compressor; is the gas compression factor of the first-stage compressor; is the final discharge pressure; is the total number of stages of the compressor; is the -th stage compressor outlet pressure.

6. The negative pressure gas production device with optimized multimodal fluid compression according to claim 5, wherein Adjust the inlet temperature, outlet temperature, and inter-stage cooling temperature drop of each stage of the compressor through the following formula: Among them, is the inlet temperature of the -th stage compressor; is the negative pressure adiabatic temperature drop; is the outlet temperature of the -th stage compressor; is the inter-stage cooling temperature drop; is the minimum outlet temperature of the cooler; is the gas adiabatic index; is the outlet temperature of the -th stage compressor; is the -th stage compressor outlet pressure; is the -th stage compressor polytropic efficiency; is the -th stage compressor outlet gas compressibility factor.

7. The negative pressure gas production device with optimized multimodal fluid compression according to claim 6, characterized in that, Calculate the polytropic efficiency of the -stage compressor using the following formula: Among them, is the designed flow rate of the compressor; is the designed pressure ratio of the compressor, and the value range is from 1.5 to 4.

0.

8. The negative pressure gas production device for multi-modal fluid compression optimization according to claim 7, characterized in that, Adjust the compression power of each stage of the compressor through the following formula: Among them, is the compression power of the -stage compressor; is the gas compression factor at the inlet of the -stage compressor.

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