A method for shale nanomicro-pore high temperature and high pressure sub-scale saturated fluid

Abstract

The application discloses a method for shale nanometer micropore high-temperature high-pressure sub-scale saturated fluid, and relates to the technical field of core saturation. The method comprises the following steps: configuring degassed crude oil and associated gas into formation gas-containing crude oil, obtaining the critical condensation temperature and critical condensation pressure of the formation gas-containing crude oil; obtaining the core of shale in a target area, and obtaining the porosity, rock density and rock pore volume of the core; performing vacuum extraction on the shale core, then heating the core to a reservoir temperature, and injecting the associated gas until the pressure of the core reaches the reservoir pressure; heating the formation gas-containing crude oil and the core to above the critical condensation temperature of the formation gas-containing crude oil, and displacing the core by using the formation gas-containing crude oil; cooling the formation gas-containing crude oil and the core to the reservoir temperature, and then displacing the core by using the formation gas-containing crude oil. The saturated core obtained by the method has higher similarity between the internal fluid and the actual reservoir.

Description

TECHNICAL FIELD

[0001] The present application relates to the technical field of core saturation, in particular to a method for high-temperature and high-pressure sub-scale saturation of shale micropore fluid. BACKGROUND

[0002] The pore size of shale reservoirs is mainly nanoscale, and some large micropores are also included. In nanometer pores, the solid-liquid interaction between the solid phase such as rock wall and the fluid in the pore is strong, and the confinement effect of the fluid in the pore is significant (i.e. nanometer confinement effect). The main performance is that the fluid adsorption amount accounts for a high proportion. The fluid adsorbed on the solid surface will cause changes in pore size and contact angle, thereby enhancing the capillary force effect. In addition, fluid adsorption leads to changes in fluid composition and molecular arrangement pattern, which has a great influence on the mass transfer law and thermodynamic properties of oil and gas, making the fluid properties and bulk phase significantly different. Based on differential scanning calorimetry, adsorption-desorption method and other micro-experimental research methods, it is shown that the critical temperature, critical pressure and saturation pressure of hydrocarbons in nanometer pores are significantly lower than those in bulk phase, and the deviation degree gradually increases as the pore size decreases. Due to the unconventional characteristics of shale oil reservoir rocks and the limitations of experimental equipment, it is very difficult to carry out experimental research on phase behavior, and the data accuracy is not high. At present, the research on micro-pore flow and phase state characteristics of shale oil and gas reservoirs mainly relies on numerical simulation and theoretical calculation.

[0003] In the sampling process of shale cores, there are currently two methods: frozen pressure core sampling and conventional core sampling. The frozen pressure core sampling can maintain the phase state of the extracted core under reservoir conditions, but the cost is extremely high. Except for a few cases, most of them use conventional core sampling method. Since shale oil usually contains a certain amount of shale gas, the light hydrocarbon in the core extracted by conventional core sampling will flow out, and part of the oil will also expand and flow out of the pore. Therefore, when performing physical simulation experiments on shale, the core is usually saturated with oil to simulate the conditions of shale under reservoir conditions.

[0004] According to the research of the prior art, due to the existence of "nanometer confinement effect", the fluid form of oil and gas in nanometer pores and micrometer pores will be different: in nanometer pores, the critical temperature and critical pressure of oil and gas are relatively low compared with large pores. Therefore, in some cases, the oil and gas in the shale reservoir will present different phase states: liquid phase in micrometer pores and condensate gas phase in nanometer pores.

[0005] The shale saturation devices in the prior art, such as CN114062610A, CN114034597A and the like, are all conventional shale saturation devices, which do not consider the "nano confinement effect", resulting in a large difference between the final detection result and the actual situation; and the existing saturation methods are all one-time saturation method or step-by-step pressurization saturation method, due to the influence of fluid adsorption in the shale reservoir, the capillary force is large, these existing methods cannot saturate nanofluid in nanometer pores, and there are problems of too large displacement pressure and destruction of micro-nanopore structure in the saturation process. SUMMARY

[0006] To solve at least one of the above problems, the present application provides a method for shale nanometer-micropore high-temperature high-pressure scale saturation of fluid.

[0007] The technical scheme of the present application is: a method for shale nanometer-micropore high-temperature high-pressure scale saturation of fluid, the method comprising the following steps:

[0008] S1, taking target area degassed crude oil and associated gas, and preparing the degassed crude oil and associated gas into formation gas-containing crude oil to obtain the critical condensation temperature of the formation gas-containing crude oil;

[0009] S2, obtaining the core of shale in the target area, and obtaining the pore volume of the core;

[0010] S3, vacuumizing the shale core, continuing to vacuumize for at least 3h after the vacuum degree reaches a first threshold value, then heating the core to the reservoir temperature, and injecting the associated gas until the core pressure reaches the reservoir pressure;

[0011] S4, heating the formation gas-containing crude oil and the core to above the critical condensation temperature of the formation gas-containing crude oil, and displacing the core with the formation gas-containing crude oil, the displacement multiple being greater than 10 times the pore volume;

[0012] S5, keeping the core pressure unchanged, cooling the formation gas-containing crude oil and the core to the reservoir temperature, and then displacing the core with the formation gas-containing crude oil, the displacement multiple being greater than 10 times the pore volume.

[0013] In an embodiment of the present application, in S1, the critical condensation temperature and the critical condensation pressure of the formation gas-containing crude oil are obtained through PVT experiment.

[0014] In an embodiment of the present application, in S3-S5, a confining pressure is applied to the shale core, the confining pressure being greater than the injection pressure and the displacement pressure.

[0015] Further, the confining pressure is at least 3MPa higher than the injection pressure and the displacement pressure.

[0016] One embodiment of the present application is that, in S3, when the vacuum degree reaches the first threshold, continue to vacuum for at least 3h; after injecting the associated gas until the core pressure reaches the reservoir pressure, continue to inject the associated gas until the pressure in the core remains stable for at least 4h.

[0017] One embodiment of the present application is that, in S3, the first threshold is 6x10 -2 Pa.

[0018] Beneficial effects: the method of the present application, considering the nanometer confinement effect, first injects a large amount of associated gas into the core, and then the associated gas is dissolved in the residual oil in the core, so that the density of the residual oil is lowered, and under the action of the associated gas, the nanometer pores in the core are filled with gas phase, and the micropores are filled with liquid phase; then, the temperature is raised to above the critical condensation temperature, so that the residual oil in the core is converted into condensate gas, and at the same time, the gas-containing crude oil arranged in the formation is also converted into condensate gas phase; at this time, when we use the condensate gas state gas-containing crude oil to displace the core, both the nanometer pores and the micropores in the core can be converted into condensate gas state gas-containing crude oil; finally, the core and the gas-containing crude oil are cooled to the reservoir temperature, at this time, the crude oil in the micropores becomes liquid, but in order to avoid the influence of the porous core on the gas-containing crude oil in the micropores during the phase transition, we continue to displace the core with the gas-containing crude oil after cooling.

[0019] Therefore, the saturated core obtained by the method of the present application considers the nanometer confinement effect, so that the core saturated with gas-containing crude oil has higher similarity to the actual reservoir. BRIEF DESCRIPTION OF DRAWINGS

[0020] Figure 1 The flow chart of the method of the embodiment of the present application.

[0021] Figure 2 The device structure schematic diagram when the method of the embodiment is applied.

[0022] In the figure, 1 is a core holder, 2 is a first intermediate container, 3 is a second intermediate container, 4 is a displacement pump, 5 is a confining pressure pump, 6 is a vacuum pump, and 7 is a heating device. DETAILED DESCRIPTION

[0023] The specific embodiments of the present application will be described below in conjunction with examples and drawings, and it is obvious that the described examples are only part of the embodiments of the present application, but not all the embodiments.

[0024] In the following examples, the formation gas-containing crude oil refers to a form in which crude oil is dissolved with a large amount of associated gas under reservoir temperature and pressure conditions, and the components, composition, viscosity, density, oil-gas ratio and other high-pressure physical property parameters of the prepared formation gas-containing crude oil are the same as those of the reservoir crude oil.

[0025] In the following examples, the critical condensation temperature refers to the highest temperature at which the oil phase in the shale oil and gas system can exist. When the system temperature is higher than the critical condensation temperature, no matter how much pressure is applied, the system will not be liquefied. In the phase diagram, the critical condensation temperature represents the highest temperature at which two phases coexist. Above this temperature, it is gaseous, and below this temperature, it is liquid.

[0026] A method for high-temperature and high-pressure scale saturation of shale nanometer micropores, when actually used, also needs to be matched with a physical experiment equipment, which can be set as a conventional displacement device.

[0027] Referring to Figure 2 In the present embodiment, the physical experiment equipment used has the following structure: a core holder 1 is provided with a shale core, the outlet end of the core holder 1 is connected with a vacuum pump 6 and a liquid discharge pipe, the peripheral side wall of the core holder 1 is further connected with a confining pressure pump 5, the inlet end of the core holder 1 is connected with a first intermediate container 2 and a second intermediate container 3, the first intermediate container 2 is filled with gas-containing crude oil, the second intermediate container 3 is filled with associated gas, and both intermediate containers are connected with a displacement pump 4. Corresponding heating devices 7 are arranged outside the core holder 1 and the first intermediate container 2.

[0028] Referring to Figure 1 The method comprises the following steps:

[0029] S1, taking target area degassed crude oil and associated gas, and configuring the degassed crude oil and the associated gas into formation gas-containing crude oil to obtain the critical condensation temperature and the critical condensation pressure of the formation gas-containing crude oil;

[0030] For the degassed crude oil and the associated gas, it is relatively easy to obtain, which can be directly sampled from the well site.

[0031] The on-site gas-oil ratio is corrected, and the volume of the degassed crude oil and the volume of the associated gas required for preparing the formation gas-containing crude oil are calculated. The degassed crude oil and the associated gas are respectively equilibrated at a constant temperature for more than 4h under the sample preparation pressure. Referring to GB / T 26981-2020 "Oil and Gas Reservoir Fluid Physical Property Analysis Method", the required amount of degassed crude oil and the required amount of associated gas are transferred into a sample preparation container by a double pump method. The fluid sample in the sample preparation container is heated to the formation temperature, and the sample is fully stirred and pressed into a single phase. After equilibration for 4h under the formation pressure, PVT analysis test is carried out to obtain the critical condensation temperature and the critical condensation pressure and other phase state parameters of the formation gas-containing crude oil.

[0032] S2, obtain a shale core of a target area, and obtain porosity, rock density and rock pore volume of the core;

[0033] In this step, the shale core used is obtained by conventional coring methods, and a certain amount of shale oil and a small amount of shale gas remain inside. Because the volume of nanoscale pores in shale reservoirs often accounts for more than 80% of the total pore volume of the core, most current displacement experiments do not wash oil but directly saturate the core. On the one hand, conventional oil washing methods such as thermal release, displacement, centrifugation and extraction are difficult to completely remove the oil phase in the nanometer pore grid, and the oil is not washed clean. On the other hand, after washing the oil, it is worried that the fluid will be difficult to completely saturate the nanometer pores after saturation.

[0034] In this embodiment, the rock pore volume of the core is measured according to the relevant requirements in GB / T 34533-2023 "Determination of Shale Porosity, Permeability and Saturation".

[0035] S3, vacuumize the shale core, continue to vacuumize for at least 3h after the vacuum degree reaches the first threshold value, then heat the core to the reservoir temperature, and inject associated gas until the core pressure reaches the reservoir pressure;

[0036] In this step, the existing vacuumizing method can be used when vacuumizing the shale core. The outlet of the core holder is vacuumized by a vacuum pump, and the inlet of the core holder is closed at the same time. The time and method of vacuumizing can also be determined according to the existing method, for example, according to the relevant requirements in GB / T 34533-2023 "Determination of Shale Porosity, Permeability and Saturation", continue to vacuumize for 4h~6h after the vacuum degree reaches 6x10 -2 Pa.

[0037] In this step, the shale core in the core holder is heated to the reservoir temperature by the heating device. After the temperature of the shale core is stable, the confining pressure is applied to the shale core by the confining pressure pump, and the associated gas in the second intermediate container is injected into the shale core by the displacement pump until the reservoir pressure is reached.

[0038] After vacuumizing the shale core, the light hydrocarbon in the shale core is extracted, but most of the oil phase may still remain inside. These oil phases are quite different from the original oil and gas components in the shale core. Therefore, the purpose of this step is to remove this part of the oil phase.

[0039] When injecting associated gas, the associated gas can dissolve in the residual oil phase in the shale core, and at the same time, the shale core is filled with fluid. At this time, compared with the original formation fluid, the fluid in the shale core dissolves excess associated gas, so the fluid is lighter than the original formation fluid, which facilitates the operation of S4. At present, the shale micron-sized large pores are in liquid phase, and the nanometer-sized small pores are in condensate gas phase due to the influence of the "nanometer confinement effect", and the critical temperature and critical pressure are lower than those of the large pores.

[0040] S4, the formation gas-containing crude oil and the core are heated to above the critical condensate temperature of the formation gas-containing crude oil, and the core is displaced by the formation gas-containing crude oil, and the displacement multiple is greater than 10 times the rock pore volume;

[0041] According to the PVT analysis test result of S1, when the formation gas-containing crude oil and the core are heated to above the critical condensate temperature, the phase state of the gas-containing crude oil in the first intermediate container will change from liquid phase to gas phase, and the fluid in the micron-sized large pores in the core will change from liquid phase to condensate gas phase, and the fluid in the nanometer-sized small pores will still be condensate gas phase. Under such conditions, by injecting the condensate gas phase formation gas-containing crude oil into the core through the displacement pump, all the fluid in the core can be replaced by the condensate gas phase formation gas-containing crude oil. After displacement, the fluid in the shale core, whether in the nanometer pores or in the micron pores, is the condensate gas phase formation gas-containing crude oil.

[0042] In this step, the temperature above the critical condensate temperature is usually required to be greater than the critical condensate temperature by 10-100℃. Of course, the temperature can be higher, but higher temperature brings higher energy consumption and higher requirements for equipment.

[0043] S5, the pressure of the core is kept unchanged, the formation gas-containing crude oil and the core are cooled to the reservoir temperature, and then the core is displaced by the formation gas-containing crude oil, and the displacement multiple is greater than 10 times the rock pore volume.

[0044] In this process, when the temperature of the formation gas-containing crude oil decreases to the reservoir temperature, the fluid in the sample preparation device returns to liquid state; in the shale core, when the temperature decreases to the reservoir temperature, the phase state of the gas-containing crude oil in the micron pores changes to liquid state, and in the nanometer pores, considering the nanometer confinement effect, the phase state is still condensate gas state.

[0045] In order to remove the influence of the gas-bearing oil in the micropores of the shale core on the phase change of the gas-bearing oil in the micropores during the phase transition process, the gas-bearing oil in the first intermediate container is continuously displaced until the oil-gas ratio, components and composition of the fluid discharged from the core holder outlet and the gas-bearing oil in the first intermediate container are the same, that is, the saturation of the shale core is considered to be completed. According to the experience of the inventor, in order to achieve the purpose, the displacement multiple is usually more than 10 PV.

[0046] The above is only a preferred embodiment of the present application, and does not limit the present application in any form. Although the present application has been disclosed as above with a preferred embodiment, it is not intended to limit the present application. Any person skilled in the art can make some changes or modifications to the above disclosed technical content to obtain equivalent embodiments with equivalent changes, without departing from the technical solution of the present application. Any simple modification, equivalent change and modification made to the above embodiments according to the technical essence of the present application are still within the scope of the technical solution of the present application.

Claims

1. A method for saturating shale nano- and micro-pores with fluid at high temperature and high pressure, characterized in that: The method comprises the following steps: S1. Obtain degassed crude oil and associated gas from the target area, mix the degassed crude oil and associated gas into formation live crude oil, and obtain the critical condensation temperature of the formation live crude oil; S2. Obtaining a core of shale in the target area and obtaining the pore volume of the core; S3. Vacuum the shale core. When the vacuum reaches a first threshold, continue pumping for at least 3 hours. Then, heat the core to the reservoir temperature and inject associated gas until the core pressure reaches the reservoir pressure. S4. heating the formation live crude oil and the core rock to above the critical condensation temperature of the formation live crude oil, and displacing the core rock with the formation live crude oil at a displacement multiple greater than 10 times the pore volume; S5. Keep the core pressure constant, cool the formation gas-bearing crude oil and the core temperature to the reservoir temperature, and then use the formation gas-bearing crude oil to displace the core, with the displacement ratio being greater than 10 times the pore volume.

2. The method according to claim 1, characterized in that In S1, the critical condensate temperature and critical condensate pressure of the gas-bearing crude oil in the formation are obtained through PVT experiments.

3. The method according to claim 1, characterized in that In S3 to S5, a confining pressure is applied to the core, and the confining pressure is greater than the injection pressure and the displacement pressure.

4. The method according to claim 3, characterized in that The confining pressure is at least 3 MPa higher than the injection pressure and the displacement pressure.

5. The method according to claim 1, wherein In S3, when the vacuum degree reaches the first threshold, the vacuum is continued for at least 3 hours; after the associated gas is injected until the core pressure reaches the reservoir pressure, the associated gas is continuously injected until the pressure in the core remains stable for at least 4 hours.

6. The method according to claim 1, characterized in that In S3, the first threshold is 6×10 -2 Pa.

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