Device and method for evaluating liquid phase damage in condensate gas reservoirs

Abstract

The present invention provides an apparatus and method for evaluating liquid phase damage in condensate gas reservoirs. The apparatus comprises a liquid injection unit, a temperature and pressure control unit, a core holder unit, an acoustic wave monitoring unit, a gas-liquid metering unit, and a data processing unit. The core holder unit comprises a core holder and a confining pressure device. The core holder comprises a kettle, a plunger, and a rubber sleeve. The kettle is a cylindrical structure with two open ends, sealed by a plunger. The rubber sleeve contains a core, which is then loaded into the kettle. The gas-liquid metering unit comprises a three-phase separator and a metering device. By configuring structural units such as liquid injection, temperature and pressure control, a core holder, and gas-liquid metering, and then designing the core holder structure, the present invention can evaluate the effects of condensate oil saturation under different water phase contents and water phase occurrence states on gas phase permeability, resulting in accurate and comprehensive evaluation results. The apparatus has a high degree of automation and intelligence, is easy to operate, and achieves high experimental accuracy.

Description

Technical Field

[0001] The invention belongs to the technical field of gas reservoir development and relates to a device and method for evaluating liquid phase damage in a condensate gas reservoir. Background Art

[0002] Natural gas, a key fossil energy source in the context of a low-carbon transition, is experiencing increasing demand. Condensate gas reservoirs, as the primary source of natural gas, play a crucial role in global gas field development, with condensate fields comprising a significant portion of both giant and large gas fields. Compared to conventional gas reservoirs, condensate gas reservoirs are distinguished by their unique phase transitions. Natural gas extraction consistently reduces formation pressure. During the development of condensate gas reservoirs, when formation pressure drops below the dew point, retrograde condensation occurs, producing condensate oil and causing severe liquid phase damage.

[0003] The production of condensate in condensate gas reservoirs changes the formation's flow from a single-phase gas flow to a two-phase flow of oil and gas. Undrained condensate can permanently impair formation permeability and even block flow pathways. Due to the complex initial water saturation in real formations, water saturation affects the flow of both the gas and oil phases, severely impacting both natural gas production and condensate discharge. Within a large condensate gas reservoir, water saturation varies across every subsurface layer, making liquid phase damage in condensate gas reservoirs a complex and complex issue. Therefore, accurately assessing the extent of liquid phase damage in condensate gas reservoirs is crucial for designing condensate reservoir development plans, formulating engineering measures, and predicting gas well production.

[0004] CN 112966365A discloses a method for evaluating retrograde condensation damage in ultra-low permeability condensate gas reservoirs. The method comprises: quantitatively characterizing the microscopic pore throat radius of the core by CT scanning a digital rock core; then, using a photolithography displacement method based on the throat radius distribution of the core, obtaining the microscopic seepage limit of different throat radii; finally, calculating the throat radius distribution in the core using a pipe flow equation to obtain the contribution of different throat radius distributions to permeability; and obtaining the damage to reservoir permeability caused by condensate oil precipitation based on the distribution of the throat radius contribution to permeability, thereby achieving a quantitative evaluation of retrograde condensation damage in ultra-low permeability condensate gas reservoirs. The method focuses on the influence of the structural dimensions and distribution of the throats within the core on the permeability of the condensate gas reservoir during retrograde condensation. However, since the method also evaluates damage to a single liquid phase, it does not address the influence of the presence of a water phase on permeability, resulting in a relatively simple evaluation index.

[0005] CN 110879196A discloses a method for testing oil-water phase permeability in an oil-rich condensate gas reservoir. The method utilizes an oil-water phase permeability testing device, which comprises an injection pump, an intermediate container, a core holder, a confining pressure pump, a back-pressure pump, a back-pressure regulator, a meter, and a flow meter. Specifically, the method includes: selecting a PVT report for an oil-rich condensate gas reservoir to obtain the fluid composition and maximum condensate oil volume of the reservoir; performing phase state simulation using WinPro software to obtain the condensate oil viscosity under formation conditions; preparing formation water and preparing simulated oil based on the oil-water viscosity ratio; measuring the length, volume, and cross-sectional area of the core, washing and drying it, and measuring its porosity; and performing an oil-water phase permeability test under formation conditions to generate a curve showing the relationship between the relative permeabilities of the oil and water phases and water saturation. This method only specifically performs an oil-water phase permeability test and does not clearly distinguish between different water phase conditions and their states, making it difficult to comprehensively and accurately assess liquid phase damage after retrograde condensation in a condensate gas reservoir.

[0006] In summary, for the reduction of seepage capacity during the development of oil-condensate gas reservoirs, the evaluation of the degree of seepage damage needs to be comprehensively evaluated under different phase states and contents to improve the accuracy of the evaluation results. Summary of the Invention

[0007] In response to the problems existing in the prior art, the purpose of the present invention is to provide a device and method for evaluating liquid phase damage in condensate gas reservoirs. By setting up structural units such as liquid injection, temperature and pressure control, core clamps, and gas-liquid metering, a set of devices for evaluating liquid phase damage in condensate gas reservoirs is designed. In particular, the structural design of the core clamp enables it to fully consider the influence of water phase conditions and water phase occurrence state on liquid phase damage evaluation. Through oil phase damage experiments under different water phase conditions, a comprehensive and accurate assessment of the degree of liquid phase damage in condensate gas reservoirs can be achieved.

[0008] To achieve this object, the present invention adopts the following technical solutions:

[0009] In one aspect, the present invention provides a device for evaluating liquid phase damage in condensate gas reservoirs, the device comprising a liquid injection unit, a temperature and pressure control unit, a core holder unit, an acoustic wave monitoring unit, a gas-liquid metering unit, and a data processing unit; the core holder unit comprising a core holder and a confining pressure device, the core holder comprising a kettle, a plunger, and a rubber sleeve; the kettle being a cylindrical structure with both ends open, the ends of the kettle being closed by the plunger; a core being placed in the rubber sleeve, and the rubber sleeve and core being placed together in the kettle; the confining pressure device being disposed outside the core holder and connected to the kettle; the gas-liquid metering unit comprising a three-phase separator and a metering device, the outlet of the three-phase separator being connected to the metering device;

[0010] The outlet of the injection unit is connected to the core holder through a liquid inlet pipeline, and the liquid inlet pipeline is connected to the core through a plunger. The other end of the core is connected to the gas-liquid metering unit through an outlet pipeline. The temperature and pressure control unit is connected to the inside of the core holder through plungers at both ends of the core holder. The acoustic wave monitoring unit is installed on the outer wall of the core holder kettle. The data processing unit is independently connected to the injection unit, the temperature and pressure control unit, the core holder unit, the acoustic wave monitoring unit, and the gas-liquid metering unit.

[0011] In the present invention, liquid phase damage of condensate gas reservoirs during development is an important evaluation indicator, and the evaluation of liquid phase damage is affected by many factors. The present invention designs a device for evaluating liquid phase damage of condensate gas reservoirs in view of the influence of condensate oil production after retrograde condensation in condensate gas reservoirs on seepage capacity. By setting structural units such as liquid injection, temperature and pressure control, a core holder, and gas-liquid metering, and by sequentially introducing water, oil, and gas phases, and then according to the structural design of the core holder, the influence of condensate oil saturation on gas phase permeability under different water phase contents and water phase occurrence states can be evaluated, and the evaluation results are accurate and comprehensive. The device has a high degree of automation and intelligence, is easy to operate, and has a high degree of experimental accuracy.

[0012] The following are preferred technical solutions of the present invention, but are not intended to limit the technical solutions provided by the present invention. Through the following technical solutions, the technical objectives and beneficial effects of the present invention can be better achieved and realized.

[0013] As a preferred technical solution of the present invention, the injection unit includes a microfluidic device and a liquid storage tank, and the liquid storage tank is connected to the microfluidic device through an infusion line.

[0014] Preferably, the liquid storage tank includes a water storage tank and an oil storage tank, which are arranged in parallel.

[0015] In the present invention, injection parameters are set on the microfluidic device, and liquid is injected into the core in the core holder through the microfluidic device.

[0016] Preferably, the temperature and pressure control unit includes a temperature control unit and a pressure control unit, and a gas storage tank, preferably a gas cylinder, is connected upstream of the temperature and pressure control unit.

[0017] Preferably, a temperature rising and controlling device and a pressure sensor are further provided inside the core holder.

[0018] Preferably, the temperature control unit is connected to the temperature raising and controlling device via plungers at both ends of the core holder.

[0019] Preferably, the pressure control unit is connected to the pressure sensor via plungers at both ends of the core holder.

[0020] In the present invention, the temperature rising and controlling device inside the core holder is connected to the temperature control unit via a data line, and temperature rising and controlling are achieved through electric heating; the pressure sensor is provided at both the inlet and outlet ends of the core, and the pressure control unit injects gas into the core holder to achieve pressure control through signal feedback from the pressure sensor.

[0021] In the present invention, the temperature and pressure control unit heats the core while applying pressure to both ends of the core to prevent phase changes caused by temperature increase.

[0022] As a preferred technical solution of the present invention, both ends of the kettle body in the core holder are connected to the plunger through a clamping groove.

[0023] Preferably, the plungers at both ends of the core holder are provided with openings, and the liquid injection unit, the temperature and pressure control unit and the gas-liquid metering unit are connected through the openings.

[0024] In the present invention, the core in the core holder is placed in a rubber sleeve, and the liquid / air inlet pipelines are both passed into the rubber sleeve, while the rubber sleeve itself is not permeable to air or water, so as to prevent hydraulic oil outside the rubber sleeve from being injected into the core and affecting the oil phase damage experiment.

[0025] Preferably, the number of openings on the plunger is 2 or 3.

[0026] In the present invention, based on the simplicity of the device, the liquid inlet pipeline and the air inlet pipeline can be integrated and arranged. In this case, the two are shared, and there are two openings on the plunger plus the data line opening. In order to facilitate operation, the liquid inlet pipeline and the air inlet pipeline can also be arranged separately. In this case, there are three openings on the plunger.

[0027] Preferably, a flow channel is provided between the outer wall and the inner wall of the kettle body, and a cooling fluid flows into the flow channel.

[0028] In the present invention, the flow channel between the outer wall and the inner wall of the kettle body can be connected to the fluid cooler of the gas-liquid metering unit to achieve rapid cooling of the kettle body after the experiment.

[0029] Preferably, the core holder further comprises a heat-insulating sleeve, which wraps the outer wall of the kettle body to reduce potential safety hazards caused by high temperature.

[0030] Preferably, the confining pressure equipment includes a confining pressure pump, which pumps hydraulic oil into the interior of the kettle body to pressurize the outer wall of the rubber sleeve to achieve confining pressure on the core.

[0031] As a preferred technical solution of the present invention, the acoustic wave monitoring unit includes an ultrasonic probe, an ultrasonic receiver and an acoustic wave data processor. The ultrasonic probe and ultrasonic receiver are integrated together and installed on the outer wall of the kettle body of the core clamp and connected to the acoustic wave data processor through a data line.

[0032] In the present invention, the ultrasonic probe and ultrasonic receiver are installed on the outer wall of the kettle body, and can be used to monitor the fluid distribution in the core and the changes in the core structure when the core begins to flow in and flow back.

[0033] Preferably, the metering equipment in the gas-liquid metering unit includes a liquid collecting tank and a gas flow meter, the liquid collecting tank includes a water collecting tank and an oil collecting tank, and the metering equipment is arranged in parallel and independently connected to the outlet of the three-phase separator.

[0034] Preferably, the gas-liquid metering unit further includes an electronic balance, and the water collecting tank and the oil collecting tank are arranged on the electronic balance.

[0035] Preferably, the gas-liquid metering unit further comprises a fluid cooler, and the fluid cooler is arranged between the core holder and the three-phase separator.

[0036] Preferably, the inlet and outlet of the cooling fluid in the fluid cooler are also connected to the flow channel of the kettle body.

[0037] In the present invention, the fluid cooler can not only cool the fluid coming from the core holder, but also cool the core holder kettle after the experiment.

[0038] Preferably, the data processing unit includes a computer, which is connected to each unit via a data line to collect and process data information.

[0039] In the present invention, the computer can collect data such as pressure, temperature, weight, flow, etc., and perform data processing to output experimental results.

[0040] On the other hand, the present invention also provides a method for evaluating liquid phase damage in a condensate gas reservoir using the above-mentioned device, the method comprising the following steps:

[0041] (1) The core drilled from the condensate gas reservoir is pre-treated and its basic parameters are measured. Then, it is loaded into the above-mentioned device, and water is first injected to measure the gas phase permeability under different water phase conditions;

[0042] (2) Carry out oil phase damage experiment under bound water conditions on the core to calculate the oil saturation S O1 And the permeability damage rate S1, the permeability damage rate S1 and oil saturation S O1 The relationship curve of

[0043] (3) Carry out oil phase damage experiment on the core under the condition of immovable water and calculate the oil saturation S O1 And the permeability damage rate S2, the permeability damage rate S2 and oil saturation S O1 The relationship curve of

[0044] (4) Carry out oil phase damage experiment under movable water conditions on the core and calculate the liquid saturation S O2 And the permeability damage rate S3, the permeability damage rate S3 and liquid saturation S O2 The relationship curve of

[0045] (5) Based on the oil phase damage test results in steps (2) to (4) above, a comprehensive evaluation of the liquid phase damage of the condensate gas reservoir is performed.

[0046] As a preferred technical solution of the present invention, the number of cores in step (1) is multiple, and they are drilled from the same condensate gas reservoir. The structures and sizes of different cores are basically the same, so that different cores can be selected for experiments under different conditions with less error in the experimental results. If the same core is selected for the experiment, it needs to be restored to a liquid-free state after the previous experiment is completed, and it needs to be heated and continuously gas-driven, which is a more cumbersome operation.

[0047] Preferably, the pretreatment in step (1) includes: drying the core and then sealing and cooling it.

[0048] Preferably, the basic parameters in step (1) include the length, diameter, weight and porosity of the core.

[0049] Preferably, the gas permeability detection process in step (1) includes: applying confining pressure to the core, adjusting the liquid inlet parameters, first injecting water into the core until the saturation under the water phase conditions to be detected is reached, then introducing the gas phase, starting displacement, and measuring the gas permeability under different water phase conditions.

[0050] Preferably, the different water phase conditions include bound water condition, immovable water condition and movable water condition, and the gas phase permeability under the bound water condition is K s , the gas permeability under the condition of immovable water is K d The gas permeability of the irreducible water saturation under the condition of movable water is K s .

[0051] As a preferred technical solution of the present invention, the process of the oil phase damage experiment in step (2) includes: after establishing the bound water saturation of the core, injecting the oil phase into the core to establish the oil saturation S O1 ; Then introduce the gas phase and start gas drive back to the oil phase to obtain the permeability damage rate S1 and oil saturation S O1 relationship curve.

[0052] Preferably, the oil saturation S in step (2) is O1 The calculation formulas for the permeability damage rate S1 are:

[0053]

[0054]

[0055] Where m1 is the mass of oil phase injected into the core, g; m2 is the mass of oil phase discharged, g; ρ o is the oil phase density, g / cm 3 ; V p is the core pore volume, cm 3 ;K i1 The oil saturation is S O1 Gas permeability at t, mD; K s is the gas permeability in the bound water state, mD.

[0056] As a preferred technical solution of the present invention, the process of the oil phase damage experiment in step (3) includes: after establishing the immovable water saturation of the core, injecting the oil phase into the core to establish the oil saturation S O1 ; Then introduce gas phase and start gas drive back oil phase to obtain permeability damage rate S2 and oil saturation S O1 relationship curve.

[0057] Preferably, the immovable water saturation in step (3) is less than the bound water saturation in step (2).

[0058] Preferably, the oil saturation S in step (3) is O1 The calculation formulas for the permeability damage rate S2 are:

[0059]

[0060]

[0061] Where m1 is the mass of oil phase injected into the core, g; m2 is the mass of oil phase discharged, g; ρ o is the oil phase density, g / cm 3 ; V p is the core pore volume, cm 3 ;K i1 The oil saturation is S O1 Gas permeability at t, mD; K d is the gas permeability under the immovable water state, mD.

[0062] As a preferred technical solution of the present invention, the process of the oil phase damage experiment in step (4) includes: after establishing movable water saturation of the core, injecting oil phase into the core to establish liquid saturation S O2 ; Then introduce the gas phase and start gas drive to return the oil phase and water phase, and obtain the permeability damage rate S3 and liquid saturation S O2 relationship curve.

[0063] Preferably, the movable water saturation in step (3) is greater than the bound water saturation in step (2).

[0064] Preferably, the liquid saturation S in step (4) is O2 The calculation formulas for the permeability damage rate S3 are:

[0065]

[0066]

[0067] Wherein, m3 is the mass of the oil phase injected into the core, g; m4 is the mass of the water phase injected into the core, g; m5 is the mass of the oil phase discharged, g; m6 is the mass of the water phase discharged; ρ o is the oil phase density, g / cm 3 ρ w is the density of the water phase, g / cm 3 , V p is the core pore volume, cm 3 ;K i2 The liquid saturation is S O2 Gas permeability at t, mD; K s is the gas permeability in the bound water state, mD.

[0068] Preferably, the operation order of steps (2)-(4) is not limited.

[0069] As a preferred technical solution of the present invention, during the oil phase damage experiment in steps (2) to (4), ultrasonic detection is performed on the morphological changes of the core to collect acoustic detection data.

[0070] In the present invention, when conducting oil phase damage experiments on the core, ultrasonic testing of the core is also required to observe whether it will deform or even be damaged under different temperatures and pressures, as well as its morphology under different liquid saturations. This test is mainly used as an objective observation condition to evaluate the state of the core itself during the experiment and ensure the smooth progress of salt treatment.

[0071] Preferably, the oil phase damage experimental results in step (5) are subjected to data analysis to obtain a comprehensive evaluation report on liquid phase damage in condensate gas reservoirs.

[0072] Compared with the prior art, the present invention has the following beneficial effects:

[0073] (1) The device of the present invention is configured with structural units such as liquid injection, temperature and pressure control, core holder, and gas-liquid metering. By sequentially introducing water, oil, and gas phases, and then based on the structural design of the core holder, the effect of condensate oil saturation on gas phase permeability under different water phase contents and water phase occurrence states can be evaluated. The evaluation results are accurate and comprehensive.

[0074] (2) The temperature and pressure control unit of the present invention can realize synchronous pressurization of the core during the heating process, eliminating the phase change of the fluid inside the core during the heating process, and the acoustic wave monitoring unit can clearly determine the distribution of the liquid phase in the core and the changes in the core structure during the injection and displacement processes;

[0075] (3) The device of the present invention has a high degree of automation and intelligence, is easy to operate, and has a high degree of experimental accuracy. BRIEF DESCRIPTION OF THE DRAWINGS

[0076] Figure 1 Schematic diagram of the structure of the device for evaluating liquid phase damage in condensate gas reservoirs provided in Example 1 of the present invention;

[0077] Components include: 1 - Liquid storage tank, 2 - Microfluidic device, 3 - Temperature and pressure control unit, 4 - Plunger, 5 - Kettle, 6 - Thermal insulation sleeve, 7 - Confining pressure device, 8 - Rubber sleeve, 9 - Ultrasonic probe, 10 - Acoustic data processor, 11 - Three-phase separator, 12 - Fluid cooler, 13 - Liquid collection tank, 14 - Electronic balance, 15 - Gas flow meter, 16 - Computer, and 17 - Gas cylinder. DETAILED DESCRIPTION

[0078] To better illustrate the present invention and facilitate understanding of the technical solution of the present invention, the present invention is further described in detail below. However, the following embodiments are merely simplified examples of the present invention and do not represent or limit the scope of protection of the present invention. The scope of protection of the present invention shall be subject to the claims.

[0079] The following are typical but non-limiting examples of the present invention:

[0080] Example 1:

[0081] This embodiment provides a device for evaluating liquid phase damage in condensate gas reservoirs. The schematic diagram of the device is shown in FIG. Figure 1 As shown, it includes a liquid injection unit, a temperature and pressure control unit 3, a core holder unit, an acoustic wave monitoring unit, a gas-liquid metering unit and a data processing unit; the core holder unit includes a core holder and a confining pressure device 7, the core holder includes a kettle 5, a plunger 4 and a rubber sleeve 8, the kettle 5 is a cylindrical structure with two ends open, the two ends of the kettle 5 are closed by the plunger 4, the rubber sleeve 8 is loaded with a core, the rubber sleeve 8 and the core are loaded into the kettle 5 together, the confining pressure device 7 is arranged outside the core holder and connected to the kettle 5; the gas-liquid metering unit includes a three-phase separator 11 and a metering device, and the outlet of the three-phase separator 11 is connected to the metering device;

[0082] The outlet of the injection unit is connected to the core holder through a liquid inlet pipeline, and the liquid inlet pipeline is connected to the core through a plunger 4. The other end of the core is connected to the gas-liquid metering unit through an outlet pipeline. The temperature and pressure control unit 3 is connected to the inside of the core holder through the plungers 4 at both ends of the core holder. The acoustic wave monitoring unit is installed on the outer wall of the core holder kettle 5. The data processing unit is independently connected to the injection unit, the temperature and pressure control unit 3, the core holder unit, the acoustic wave monitoring unit, and the gas-liquid metering unit.

[0083] The injection unit includes a microfluidic device 2 and a liquid storage tank 1, and the liquid storage tank 1 is connected to the microfluidic device 2 through an infusion line.

[0084] The liquid storage tank 1 includes a water storage tank and an oil storage tank, which are arranged in parallel.

[0085] The temperature and pressure control unit 3 includes a temperature control unit and a pressure control unit. A gas cylinder 17 is connected upstream of the temperature and pressure control unit 3 .

[0086] A temperature raising and controlling device and a pressure sensor are also provided inside the core holder.

[0087] The temperature control unit is connected to the temperature raising and controlling device via plungers 4 at both ends of the core holder.

[0088] The pressure control unit is connected to the pressure sensor via the plungers 4 at both ends of the core holder.

[0089] Both ends of the kettle body 5 in the core holder are connected to the plunger 4 through slots.

[0090] The plungers 4 at both ends of the core holder are provided with openings, through which the liquid injection unit, the temperature and pressure control unit 3 and the gas-liquid metering unit are connected;

[0091] The number of openings on the plunger 4 is 2.

[0092] A flow channel is provided between the outer wall and the inner wall of the kettle body 5 , and a cooling fluid flows into the flow channel.

[0093] The core holder further includes a heat-insulating sleeve 6 , which wraps the outer wall of the kettle body 5 .

[0094] The confining pressure device 7 includes a confining pressure pump, which pumps hydraulic oil into the interior of the kettle.

[0095] The acoustic wave monitoring unit includes an ultrasonic probe 9, an ultrasonic receiver and an acoustic wave data processor 10. The ultrasonic probe 9 and the ultrasonic receiver are integrated together and installed on the outer wall of the kettle body 5 of the core clamp, and are connected to the acoustic wave data processor 10 through a data line.

[0096] The metering equipment in the gas-liquid metering unit includes a liquid collecting tank 13 and a gas flow meter 15 . The liquid collecting tank 13 includes a water collecting tank and an oil collecting tank. The metering equipment is arranged in parallel and independently connected to the outlet of the three-phase separator 11 .

[0097] The gas-liquid metering unit further includes an electronic balance 14 , and the water collecting tank and the oil collecting tank are arranged on the electronic balance 14 .

[0098] The gas-liquid metering unit further includes a fluid cooler 12 , which is disposed between the core holder and the three-phase separator 11 .

[0099] The inlet and outlet of the cooling fluid in the fluid cooler 12 are also connected to the flow channel of the kettle body 5 .

[0100] The data processing unit includes a computer 16, which is connected to each unit via a data line to collect and process data information.

[0101] Example 2:

[0102] This embodiment provides a device for evaluating liquid phase damage in a condensate gas reservoir, comprising a liquid injection unit, a temperature and pressure control unit 3, a core holder unit, an acoustic wave monitoring unit, a gas-liquid metering unit, and a data processing unit. The core holder unit comprises a core holder and a confining pressure device 7. The core holder comprises a kettle 5, a plunger 4, and a rubber sleeve 8. The kettle 5 is a cylindrical structure with two open ends, and both ends of the kettle 5 are sealed by the plunger 4. A core is placed in the rubber sleeve 8, and the rubber sleeve 8 and the core are placed together in the kettle 5. The confining pressure device 7 is disposed outside the core holder and connected to the kettle 5. The gas-liquid metering unit comprises a three-phase separator 11 and a metering device. The outlet of the three-phase separator 11 is connected to the metering device.

[0103] The outlet of the injection unit is connected to the core holder through a liquid inlet pipeline, and the liquid inlet pipeline is connected to the core through a plunger 4. The other end of the core is connected to the gas-liquid metering unit through an outlet pipeline. The temperature and pressure control unit 3 is connected to the inside of the core holder through the plungers 4 at both ends of the core holder. The acoustic wave monitoring unit is installed on the outer wall of the core holder kettle 5. The data processing unit is independently connected to the injection unit, the temperature and pressure control unit 3, the core holder unit, the acoustic wave monitoring unit, and the gas-liquid metering unit.

[0104] The injection unit includes a microfluidic device 2 and a liquid storage tank 1, and the liquid storage tank 1 is connected to the microfluidic device 2 through an infusion line.

[0105] The liquid storage tank 1 includes a water storage tank and an oil storage tank, which are arranged in parallel.

[0106] The temperature and pressure control unit 3 includes a temperature control unit and a pressure control unit. A gas cylinder 17 is connected upstream of the temperature and pressure control unit 3 .

[0107] A temperature raising and controlling device and a pressure sensor are also provided inside the core holder.

[0108] The temperature control unit is connected to the temperature raising and controlling device via plungers 4 at both ends of the core holder.

[0109] The pressure control unit is connected to the pressure sensor via the plungers 4 at both ends of the core holder.

[0110] Both ends of the kettle body 5 in the core holder are connected to the plunger 4 through slots.

[0111] The plungers 4 at both ends of the core holder are provided with openings, through which the liquid injection unit, the temperature and pressure control unit 3 and the gas-liquid metering unit are connected;

[0112] The number of openings on the plunger 4 is 3.

[0113] A flow channel is provided between the outer wall and the inner wall of the kettle body 5 , and a cooling fluid flows into the flow channel.

[0114] The confining pressure device 7 includes a confining pressure pump, which pumps hydraulic oil into the interior of the kettle.

[0115] The acoustic wave monitoring unit includes an ultrasonic probe 9, an ultrasonic receiver and an acoustic wave data processor 10. The ultrasonic probe 9 and the ultrasonic receiver are integrated together and installed on the outer wall of the kettle body 5 of the core clamp, and are connected to the acoustic wave data processor 10 through a data line.

[0116] The metering equipment in the gas-liquid metering unit includes a liquid collecting tank 13 and a gas flow meter 15 . The liquid collecting tank 13 includes a water collecting tank and an oil collecting tank. The metering equipment is arranged in parallel and independently connected to the outlet of the three-phase separator 11 .

[0117] The gas-liquid metering unit further includes an electronic balance 14 , and the water collecting tank and the oil collecting tank are arranged on the electronic balance 14 .

[0118] The gas-liquid metering unit further includes a fluid cooler 12 , which is disposed between the core holder and the three-phase separator 11 .

[0119] The data processing unit includes a computer 16, which is connected to each unit via a data line to collect and process data information.

[0120] Example 3:

[0121] This embodiment provides a method for evaluating liquid phase damage in a condensate gas reservoir. The method is performed using the apparatus in Example 1 and includes the following steps:

[0122] (1) Pre-treating a core drilled from a condensate gas reservoir, wherein the core is drilled from the same condensate gas reservoir, wherein the pre-treating comprises drying the core, sealing and cooling the core, measuring its basic parameters, including the core's length, diameter, weight, and porosity, and then placing the core into the above-mentioned apparatus, first injecting water, and measuring the gas permeability under different water phase conditions;

[0123] The gas permeability test process includes: applying confining pressure to the core, adjusting the fluid inlet parameters, first injecting water into the core until the saturation under the water phase conditions to be tested is reached, then introducing gas phase to start displacement, and measuring the gas permeability under different water phase conditions, wherein the different water phase conditions include bound water conditions, immovable water conditions, and movable water conditions, wherein the gas permeability under bound water conditions is K s , the gas permeability under the condition of immovable water is K d The gas permeability of the irreducible water saturation under the condition of movable water is K s ;

[0124] (2) An oil phase damage experiment is conducted on the core under the condition of bound water. The process of the oil phase damage experiment includes: after establishing bound water saturation of the core, injecting oil phase into the core to establish oil saturation S O1 ; Then introduce gas phase, start gas drive and flowback oil phase, calculate the permeability damage rate S1, and obtain the permeability damage rate S1 and oil saturation S O1 The relationship curve of

[0125] The oil saturation S O1 The calculation formulas for the permeability damage rate S1 are:

[0126]

[0127]

[0128] Where m1 is the mass of oil phase injected into the core, g; m2 is the mass of oil phase discharged, g; ρ o is the oil phase density, g / cm 3 ; V p is the core pore volume, cm 3 ;K i1 The oil saturation is S O1 Gas permeability at t, mD; K s is the gas permeability in the bound water state, mD;

[0129] (3) An oil phase damage experiment is conducted on the core under the condition of immovable water. The process of the oil phase damage experiment includes: after establishing the immovable water saturation of the core, injecting the oil phase into the core to establish the oil saturation S O1 ; Then introduce gas phase, start gas drive and flowback oil phase, calculate the permeability damage rate S2, and obtain the permeability damage rate S2 and oil saturation S O1 The relationship curve of

[0130] The oil saturation S O1 The calculation formulas for the permeability damage rate S2 are:

[0131]

[0132]

[0133] Where m1 is the mass of oil phase injected into the core, g; m2 is the mass of oil phase discharged, g; ρ o is the oil phase density, g / cm 3 ; V p is the core pore volume, cm 3 ;K i1 The oil saturation is S O1 Gas permeability at t, mD; K d is the gas permeability under immovable water conditions, mD;

[0134] (4) Conducting an oil phase damage experiment on the core under movable water conditions. The process of the oil phase damage experiment includes: after establishing movable water saturation for the core, injecting oil phase into the core to establish liquid saturation S O2 Then, the gas phase is introduced to start the gas drive backflow of oil and water phases, and the permeability damage rate S3 is calculated to obtain the permeability damage rate S3 and liquid saturation S O2 The relationship curve of

[0135] The liquid saturation S O2 The calculation formulas for the permeability damage rate S3 are:

[0136]

[0137]

[0138] Wherein, m3 is the mass of the oil phase injected into the core, g; m4 is the mass of the water phase injected into the core, g; m5 is the mass of the oil phase discharged, g; m6 is the mass of the water phase discharged; ρ o is the oil phase density, g / cm 3 ρ w is the density of the water phase, g / cm 3 , V pis the core pore volume, cm 3 ;K i2 The liquid saturation is S O2 Gas permeability at t, mD; K s is the gas permeability in the bound water state, mD;

[0139] (5) Based on the oil phase damage experimental results in steps (2) to (4) above, after data analysis, the degree of liquid phase damage of the condensate gas reservoir at different oil saturations and different water saturations is evaluated to obtain a comprehensive evaluation report on the liquid phase damage of the condensate gas reservoir.

[0140] When the above method is used to conduct oil phase damage experiments under different water phase conditions, the change in gas phase permeability is basically that the gas phase permeability gradually decreases with the increase of oil saturation. Among them, under the condition of bound water in step (2), when the oil saturation is in the range of 50-80%, the ratio of its gas phase permeability to the gas phase permeability under the condition of bound water can be reduced from 0.25 to almost 0; under the condition of immovable water in step (3), when the oil saturation is in the range of 40-80%, the ratio of its gas phase permeability to the gas phase permeability under the condition of immovable water can be gradually reduced from 0.35 to 0.03; under the condition of immovable water in step (4), when the liquid saturation is in the range of 60-80%, the ratio of its gas phase permeability to the gas phase permeability under the condition of bound water can be reduced from 0.22 to almost 0;

[0141] After the oil phase damage experiment, the gas phase permeability can be partially restored during flowback, and basically no longer changes after reaching a certain level. Among them, under the condition of bound water in step (2), the permeability can be restored to 24.5% after 6 hours of flowback, that is, the gas phase permeability damage rate under this condition is 75.5%; under the condition of immovable water in step (3), the permeability can be restored to 35.2% after 14 hours of flowback, that is, the gas phase permeability damage rate under this condition is 64.8%; under the condition of immovable water in step (4), the permeability can be restored to 21.4% after 6 hours of flowback, that is, the gas phase permeability damage rate under this condition is 78.6%.

[0142] From the above embodiments, it can be seen that the device of the present invention, through the arrangement of structural units such as injection, temperature and pressure control, core holder and gas-liquid metering, can evaluate the influence of condensate oil saturation on gas phase permeability under different water phase contents and water phase occurrence states according to the structural design of the core holder by sequentially introducing water, oil and gas phases, and the evaluation result is accurate and comprehensive. The temperature and pressure control unit of the present invention can realize synchronous pressurization of the core during the heating process, eliminating the phase change of the fluid inside the core during the heating process, and the acoustic wave monitoring unit can clearly determine the distribution of the liquid phase in the core and the changes in the structure of the core itself during the injection and displacement processes. The device has a high degree of automation and intelligence, is easy to operate, and has a high degree of experimental accuracy.

[0143] While the present invention uses the above-described embodiments to illustrate the detailed apparatus and method of the present invention, the present invention is not limited to the above-described detailed apparatus and method. This does not necessarily mean that the present invention must rely on the above-described detailed apparatus and method in order to be implemented. Those skilled in the art will appreciate that any improvements to the present invention, equivalent replacements for the apparatus of the present invention, additions of auxiliary devices, and selections of specific methods, etc., fall within the scope of protection and disclosure of the present invention.

Claims

1. A method for evaluating liquid phase damage in a condensate gas reservoir, characterized in that: The method comprises the following steps: (1) The cores drilled from the condensate gas reservoir are pre-treated and their basic parameters are measured. Then, they are loaded into the device and water is first injected to test the gas permeability under different water phase conditions. The gas permeability test process includes: applying confining pressure to the core, adjusting the fluid injection parameters, first injecting water into the core until the saturation under the water phase conditions to be tested is reached, then introducing gas phase to start displacement, and measuring the gas permeability under different water phase conditions; (2) Carry out oil phase damage experiment under bound water conditions on the core to calculate the oil saturation S O1 And the permeability damage rate S1, the permeability damage rate S1 and oil saturation S O1 The relationship curve of The process of the oil phase damage experiment includes: after establishing the bound water saturation of the core, injecting the oil phase into the core to establish the oil saturation S O1 ; Then introduce the gas phase and start gas drive back to the oil phase to obtain the permeability damage rate S1 and oil saturation S O1 The relationship curve of (3) Carry out oil phase damage experiment on the core under the condition of immovable water and calculate the oil saturation S O1 And the permeability damage rate S2, the permeability damage rate S2 and oil saturation S O1 The relationship curve of The process of the oil phase damage experiment includes: after establishing the immovable water saturation of the core, injecting the oil phase into the core to establish the oil saturation S O1 ; Then introduce gas phase and start gas drive back oil phase to obtain permeability damage rate S2 and oil saturation S O1 The relationship curve of (4) Carry out oil phase damage experiment under movable water conditions on the core and calculate the liquid saturation S O2 And the permeability damage rate S3, the permeability damage rate S3 and liquid saturation S O2 The relationship curve of The process of the oil phase damage experiment includes: after establishing the movable water saturation of the core, injecting the oil phase into the core to establish the liquid saturation S O2 ; Then introduce the gas phase and start gas drive to return the oil phase and water phase, and obtain the permeability damage rate S3 and liquid saturation S O2 The relationship curve (5) Based on the oil phase damage test results in steps (2)-(4), a comprehensive evaluation of the liquid phase damage of the condensate gas reservoir is performed.

2. The method according to claim 1, characterized in that The number of the cores in step (1) is multiple and they are drilled from the same condensate gas reservoir.

3. The method according to claim 1, characterized in that The pretreatment in step (1) includes: drying the core and then sealing and cooling it.

4. The method according to claim 1, wherein The basic parameters in step (1) include the length, diameter, weight and porosity of the core.

5. The method according to claim 1, wherein The different water phase conditions include bound water condition, immovable water condition and movable water condition. The gas phase permeability under the bound water condition is K s , the gas permeability under the condition of immovable water is K d The gas permeability of the irreducible water saturation under the condition of movable water is K s .

6. The method according to claim 1, characterized in that The oil saturation S in step (2) O1 The calculation formulas for the permeability damage rate S1 are: Where m1 is the mass of oil phase injected into the core, g; m2 is the mass of oil phase discharged, g; ρ o is the oil phase density, g / cm 3 ; V p is the core pore volume, cm 3 ;K i1 The oil saturation is S O1 Gas permeability at t, mD; K s is the gas permeability in the bound water state, mD.

7. The method according to claim 1, characterized in that The immovable water saturation in step (3) is less than the bound water saturation in step (2).

8. The method according to claim 1, characterized in that The oil saturation S in step (3) O1 The calculation formulas for the permeability damage rate S2 are: Where m1 is the mass of oil phase injected into the core, g; m2 is the mass of oil phase discharged, g; ρ o is the oil phase density, g / cm 3 ; V p is the core pore volume, cm 3 ;K i1 The oil saturation is S O1 Gas permeability at t, mD; K d is the gas permeability under the immovable water state, mD.

9. The method according to claim 1, characterized in that The movable water saturation in step (3) is greater than the bound water saturation in step (2).

10. The method according to claim 1, characterized in that The liquid saturation S in step (4) O2 The calculation formulas for the permeability damage rate S3 are: Wherein, m3 is the mass of the oil phase injected into the core, g; m4 is the mass of the water phase injected into the core, g; m5 is the mass of the oil phase discharged, g; m6 is the mass of the water phase discharged; ρ o is the oil phase density, g / cm 3 ρ w is the density of the water phase, g / cm 3 , V p is the core pore volume, cm 3 ;K i2 The liquid saturation is S O2 Gas permeability at t, mD; K s is the gas permeability in the bound water state, mD.

11. The method according to claim 1, wherein The order of operations of steps (2)-(4) is not limited.

12. The method according to claim 1, characterized in that During the oil phase damage experiment in steps (2) to (4), ultrasonic testing is performed on the morphological changes of the core to collect acoustic detection data.

13. The method according to claim 1, wherein The oil phase damage experimental results in step (5) are subjected to data analysis to obtain a comprehensive evaluation report on liquid phase damage in condensate gas reservoirs.

14. The method according to claim 1, wherein The device includes a liquid injection unit, a temperature and pressure control unit, a core holder unit, an acoustic wave monitoring unit, a gas-liquid metering unit and a data processing unit; The core holder unit includes a core holder and a confining pressure device, the core holder includes a kettle, a plunger and a rubber sleeve, the kettle is a cylindrical structure with two ends open, the two ends of the kettle are closed by the plunger, the core is loaded into the rubber sleeve, and the rubber sleeve and the core are loaded into the kettle together, the confining pressure device is arranged outside the core holder and connected to the kettle; a temperature control device and a pressure sensor are also provided inside the core holder; a flow channel is provided between the outer wall and the inner wall of the kettle, and a cooling fluid is passed through the flow channel; The temperature and pressure control unit includes a temperature control unit and a pressure control unit. A gas storage tank is connected upstream of the temperature and pressure control unit. The temperature control unit is connected to a temperature rising and controlling device via plungers at both ends of the core holder. The pressure control unit is connected to a pressure sensor via plungers at both ends of the core holder. The acoustic wave monitoring unit includes an ultrasonic probe, an ultrasonic receiver and an acoustic wave data processor. The ultrasonic probe and the ultrasonic receiver are integrated together and installed on the outer wall of the kettle of the core holder and are connected to the acoustic wave data processor through a data line. The gas-liquid metering unit includes a three-phase separator and a metering device, wherein the outlet of the three-phase separator is connected to the metering device; the gas-liquid metering unit also includes a fluid cooler, which is arranged between the core holder and the three-phase separator; the inlet and outlet of the cooling fluid in the fluid cooler are also connected to the flow channel of the kettle body; The outlet of the injection unit is connected to the core holder through a liquid inlet pipeline, and the liquid inlet pipeline is connected to the core through a plunger. The other end of the core is connected to the gas-liquid metering unit through an outlet pipeline. The data processing unit is independently connected to the injection unit, the temperature and pressure control unit, the core holder unit, the acoustic wave monitoring unit, and the gas-liquid metering unit.

15. The method according to claim 14, characterized in that The injection unit includes a microfluidic device and a liquid storage tank, and the liquid storage tank is connected to the microfluidic device through an infusion line.

16. The method according to claim 15, characterized in that The liquid storage tank includes a water storage tank and an oil storage tank, which are arranged in parallel.

17. The method according to claim 14, characterized in that The gas storage tank is a gas cylinder.

18. The method according to claim 14, characterized in that Both ends of the kettle body in the core holder are connected to the plunger through clamping grooves.

19. The method according to claim 14, wherein The plungers at both ends of the core holder are provided with openings, through which the liquid injection unit, the temperature and pressure control unit and the gas-liquid metering unit are connected.

20. The method according to claim 14, wherein The number of openings on the plunger is 2 or 3.

21. The method according to claim 14, wherein The core holder further comprises a heat-insulating sleeve, which wraps the outer wall of the kettle body.

22. The method according to claim 14, wherein The confining pressure equipment includes a confining pressure pump, which pumps hydraulic oil into the interior of the kettle.

23. The method according to claim 14, wherein The metering equipment in the gas-liquid metering unit includes a liquid collecting tank and a gas flow meter. The liquid collecting tank includes a water collecting tank and an oil collecting tank. The metering equipment is arranged in parallel and independently connected to the outlet of the three-phase separator.

24. The method according to claim 23, wherein The gas-liquid metering unit further comprises an electronic balance, and the water collecting tank and the oil collecting tank are arranged on the electronic balance.

25. The method according to claim 14, wherein The data processing unit includes a computer, which is connected to each unit via a data line to collect and process data information.

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