Shale nano-micron pore high-temperature high-pressure scale-division fluid saturation method

Abstract

The invention discloses a shale nano-micron pore high-temperature and high-pressure scale-division fluid saturation method, and relates to the technical field of core saturation. The method comprises the following steps: preparing degassing crude oil and associated gas into formation gas-containing crude oil, and obtaining the critical condensation temperature and the critical condensation pressure of the formation gas-containing crude oil; obtaining the core of the shale in the target area, and obtaining the porosity, the rock density and the rock pore volume of the core; the shale core is vacuumized, then the core is heated to the reservoir temperature, and associated gas is injected until the core pressure reaches the reservoir pressure; the stratum gas-bearing crude oil and the rock core are heated to the temperature above the critical condensation temperature of the stratum gas-bearing crude oil, and the stratum gas-bearing crude oil is used for displacing the rock core; and the stratum gas-containing crude oil and the core are cooled to the reservoir temperature, and then the stratum gas-containing crude oil is used for displacing the core. According to the saturated rock core obtained through the method, the internal fluid of the saturated rock core and an actual reservoir stratum have higher similarity.

Description

Technical Field

[0001] The invention relates to the technical field of core saturation, and in particular to a method for high-temperature and high-pressure scale saturation of shale nano- and micro-pores with fluid. Background Art

[0002] The pore size of shale reservoirs is mainly nanoscale, and there are also some micron-scale large pores. In nanopores, the solid-liquid interaction between the solid phase such as the rock wall and the fluid in the pore is strong, and the confinement effect on the fluid in the pore is significant (i.e., nanoconfinement effect), which is mainly manifested in the high proportion of fluid adsorption. Fluid adsorption on the solid surface will cause changes in pore size and contact angle, thereby enhancing the capillary force. In addition, fluid adsorption causes changes in fluid composition and molecular arrangement pattern, which in turn has a great impact on the oil and gas mass transfer law and thermodynamic properties, making the fluid physical properties significantly different from the bulk phase. Microscopic experimental research methods such as differential thermal scanning and adsorption-desorption methods show that the critical temperature, critical pressure, and saturation pressure of hydrocarbons in nanopores are significantly lower than those in the bulk phase, and the degree of deviation 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 the microscopic seepage and phase characteristics of shale oil and gas reservoirs mainly relies on numerical simulation and theoretical calculation.

[0003] The sampling process of shale cores is currently divided into cryo-pressure coring and conventional coring. Cryo-pressure coring allows the extracted cores to maintain the phase state under reservoir conditions, but its cost is extremely high. Except for a few cases, most of them use conventional coring methods. Since shale oil usually contains a certain amount of shale gas, for conventional coring, the light hydrocarbons in the extracted cores will be lost, and some oil products will also expand and flow out of the pores. Therefore, when conducting physical simulation experiments on shale, the cores are usually saturated with oil to simulate the situation of shale under reservoir conditions.

[0004] According to the research of existing technologies, due to the existence of "nano-confinement effect", the fluid morphology of oil and gas in nanopores and micropores will be different: in nanopores, the critical temperature and critical pressure of oil and gas are lower than those in large pores. Therefore, in some cases, the oil and gas in shale reservoirs will present different phases: liquid phase in micropores and condensate gas phase in nanopores.

[0005] The shale saturation devices in the prior art, such as CN114062610A, CN114034597A, etc., are all conventional shale saturation devices, which do not take the "nano confinement effect" into consideration, resulting in a large difference between the final detection results and the actual situation; and the existing saturation methods are all single saturation methods or step-by-step pressurization saturation methods. Due to the influence of fluid adsorption in the shale reservoir, the capillary force is large. These existing methods are unable to saturate the nanopores with nanofluids, and there are problems of excessive displacement pressure and destruction of the micro-nano pore structure during the saturation process. Summary of the invention

[0006] In order to solve at least one of the above problems, the present invention proposes a method for shale nano- and micro-pore saturation with fluid at high temperature and high pressure.

[0007] The technical solution of the present invention is: a method for shale nano-micron pore high temperature and high pressure scale saturated fluid, the method comprising the following steps: S1. Take degassed crude oil and associated gas from the target area, and prepare the degassed crude oil and associated gas into formation gas-bearing crude oil, and obtain the critical condensation temperature of the formation gas-bearing crude oil; S2. Obtaining a core of shale in a target area and obtaining a pore volume of the core; S3, evacuate the shale core, and when the vacuum reaches the first threshold, continue evacuating 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 gas-bearing crude oil and the core to above the critical condensation temperature of the formation gas-bearing crude oil, and displacing the core with the formation gas-bearing crude oil, with the displacement multiple being greater than 10 times the pore volume; S5. Keep the core pressure unchanged, cool the formation gas-bearing crude oil and core temperature to the reservoir temperature, and then use the formation gas-bearing crude oil to displace the core, with the displacement multiple being greater than 10 times the pore volume.

[0008] One implementation of the present invention is that in S1, the critical condensation temperature and critical condensation pressure of the gas-bearing crude oil in the formation are obtained through a PVT experiment.

[0009] An implementation of the present invention is that in S3 to S5, a confining pressure is applied to the shale core, and the confining pressure is greater than the injection pressure and the displacement pressure.

[0010] Furthermore, the confining pressure is at least 3 MPa higher than the injection pressure and the displacement pressure.

[0011] One implementation of the present invention is that in S3, after the vacuum degree reaches a first threshold, vacuuming 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.

[0012] One implementation of the present invention is that in S3, the first threshold is 6×10 -2 Pa.

[0013] Beneficial effect: The method of the present invention takes into account the nano-confinement effect. First, after a large amount of associated gas is injected into the core, the associated gas dissolves in the residual oil in the core, so that the residual oil density becomes lower. Under the action of the associated gas, the nanopores in the core are filled with the gas phase, and the micron pores are filled with the 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 the configured formation gas-bearing crude oil is also converted into a condensate gas phase. At this time, when we use the condensate gas-containing crude oil to displace the core, both the nanopores and the micron pores in the core can be converted into condensate gas-containing crude oil; finally, the core and the formation gas-bearing crude oil are cooled to the reservoir temperature. At this time, the crude oil in the micron pores becomes liquid. However, in order to avoid the influence of the porous core on the formation gas-bearing crude oil in the micron pores during the phase transition process, we use the cooled formation gas-bearing crude oil to continue to displace the core.

[0014] Therefore, the saturated core obtained by the method of the present invention takes the nano-confinement effect into consideration, so that the internal fluid of the core after saturating the gas-bearing crude oil in the formation has a higher similarity with the actual reservoir. BRIEF DESCRIPTION OF THE DRAWINGS

[0015] Figure 1 The figure is a flow chart of a method according to an embodiment of the present invention.

[0016] Figure 2 Schematic diagram of the device structure when the method of this embodiment is applied.

[0017] 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

[0018] The specific implementation modes of the present invention will be described clearly and completely below with reference to examples and drawings. Obviously, the described examples are only some embodiments of the present invention, rather than all embodiments.

[0019] In the following embodiments, the gas-bearing crude oil refers to a form of crude oil in which a large amount of associated gas is dissolved under the temperature and pressure conditions of the reservoir, and the components, composition, viscosity, density, oil-gas ratio and other high-pressure physical properties of the prepared gas-bearing crude oil are the same as the parameters of the reservoir crude oil.

[0020] In the following embodiments, the critical condensation temperature refers to the highest temperature at which the oil phase can exist in the shale oil and gas system. When the system temperature is higher than the critical condensation temperature, the system will not liquefy no matter how much pressure is applied. In the phase diagram, the critical condensation temperature is expressed as the highest temperature at which two phases coexist. Above this temperature, it is gaseous, and below this temperature, it is liquid.

[0021] A method for high-temperature and high-pressure scale saturation of shale nano- and micron-pores with fluid, when actually used, also requires matching physical experimental equipment, which can be set as a conventional displacement device.

[0022] See also Figure 2 In this embodiment, the structure of the physical experiment equipment used is as follows: it includes a core holder 1, a shale core is arranged in the core holder 1, the outlet end of the core holder 1 is connected to a vacuum pump 6 and a liquid discharge pipe, the peripheral wall of the core holder 1 is also connected to a confining pressure pump 5, the inlet end of the core holder 1 is connected to a first intermediate container 2 and a second intermediate container 3, wherein 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 to a displacement pump 4. Corresponding heating devices 7 are arranged outside the core holder 1 and the first intermediate container 2.

[0023] See also Figure 1 , the method comprises the following steps: S1. Take degassed crude oil and associated gas in the target area, and configure the degassed crude oil and associated gas into formation gas-bearing crude oil, and obtain the critical condensate temperature and critical condensate pressure of the formation gas-bearing crude oil; Degassed crude oil and associated gas are relatively easy to obtain and can be directly sampled from the well site.

[0024] The on-site gas-oil ratio is corrected, and the volume of degassed crude oil and associated gas required for preparing the formation gas-bearing crude oil is calculated. Under the sampling pressure, the degassed crude oil and associated gas are respectively balanced at a constant temperature for more than 4 hours. Referring to GB / T 26981-2020 "Analysis Methods for Physical Properties of Oil and Gas Reservoir Fluids", the required amount of degassed crude oil and associated gas is transferred into the sampling container by the double pump method, the fluid sample in the sampling container is heated to the formation temperature, and the sample is fully stirred and pressed into a single phase. After balancing at the formation pressure for 4 hours, the PVT analysis test is carried out to obtain the phase parameters such as the critical condensation temperature and critical condensation pressure of the formation gas-bearing crude oil.

[0025] S2. Obtaining a core of shale in the target area, and obtaining the porosity, rock density and rock pore volume of the core; In this step, the shale core used is obtained by conventional coring methods, and there is still a certain amount of shale oil and a small amount of shale gas inside. Since the nanoscale pore volume in shale reservoirs can often reach more than 80% of the total pore volume of the core, most of the current displacement experiments do not wash the oil but directly saturate the core: on the one hand, conventional thermal release method, displacement method, centrifugal method, extraction method and other oil washing methods are difficult to completely expel the oil phase in the nanopore grid, and the oil washing is not clean; on the other hand, after washing the oil, re-saturating the fluid is worried that the fluid will not be able to completely saturate the nanopores.

[0026] In this embodiment, the rock pore volume of the core is measured according to the relevant requirements of GB / T 34533-2023 "Determination of Porosity, Permeability and Saturation of Shale".

[0027] S3, evacuate the shale core, and when the vacuum reaches the first threshold, continue evacuating 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; In this step, when vacuuming the shale core, the existing vacuuming method can be used. The outlet of the core holder is vacuumed by a vacuum pump, and the inlet of the core holder is closed at the same time. The time and method of vacuuming can also be determined according to the existing method. For example, according to the relevant requirements of GB / T 34533-2023 "Determination of Porosity, Permeability and Saturation of Shale", when the vacuum degree reaches 6×10 -2 After Pa, continue pumping for 4h~6h.

[0028] In this step, the shale core in the core holder is heated to the reservoir temperature by a heating device. After the temperature of the shale core is stabilized, a confining pressure is applied to the shale core by a confining pressure pump, and at the same time, the associated gas in the second intermediate container is injected into the shale core by a displacement pump until the reservoir pressure is reached.

[0029] After the shale core is vacuumed, the light hydrocarbons in the shale core are extracted, but most of the oil phase may still remain inside, and 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.

[0030] When the associated gas is injected, the associated gas can be dissolved in the residual oil phase in the shale core, and at the same time the shale core is filled with fluid. At this time, the fluid inside the shale core has dissolved excess associated gas compared to the original formation fluid, so the fluid properties are "lighter" than the original formation fluid, which is convenient for the operation of S4. In the current state, the micron-scale large pores of the shale are liquid phase, and due to the influence of the "nano-confinement effect" in the nano-scale small pores, the critical temperature and critical pressure are lower than those of the large pores, and the oil and gas phase is manifested as a condensate gas phase.

[0031] S4, heating the formation gas-bearing crude oil and the core to above the critical condensation temperature of the formation gas-bearing crude oil, and displacing the core with the formation gas-bearing crude oil, with the displacement multiple being greater than 10 times the rock pore volume; From the PVT analysis test results of S1, it can be seen that when the temperature of the gas-bearing crude oil and the core is heated to above the critical condensation temperature, the phase of the gas-bearing crude oil in the first intermediate container will change from liquid to gas. At the same time, the fluid in the micron-sized pores in the core changes from liquid to condensed gas, and the fluid in the nano-sized pores is still condensed gas. Under such conditions, the injection of gas-bearing crude oil in the condensed gas phase into the core by the displacement pump can replace all the fluids in the core with gas-bearing crude oil in the condensed gas phase. After the displacement is completed, the fluid in the shale core, whether it is nanopores or micropores, is gas-bearing crude oil in the condensed gas phase.

[0032] In this step, the temperature above the critical condensation temperature is usually required to be 10-100°C higher than the critical condensation temperature. Of course, the temperature can also be higher, but a higher temperature brings higher energy consumption and also places higher requirements on the equipment.

[0033] S5. Keep the core pressure unchanged, cool the formation gas-bearing crude oil and core temperature to the reservoir temperature, and then use the formation gas-bearing crude oil to displace the core, with the displacement multiple being greater than 10 times the rock pore volume.

[0034] In this process, when the temperature of the gas-containing crude oil in the formation drops to the reservoir temperature, the fluid phase in the sampler returns to liquid state; in the shale core, when its temperature drops to the reservoir temperature, the phase of the gas-containing crude oil in its micron pores changes to liquid state, and in the nanopores, considering the nano confinement effect, its phase is still condensed gas.

[0035] In order to remove the influence of porous medium interface phenomenon on the phase change of the gas-bearing crude oil in the micron pores of the shale core during the phase transition, we continue to use the gas-bearing crude oil in the first intermediate container to displace it until the fluid discharged from the core holder outlet and the gas-bearing crude oil in the first intermediate container have the same oil-gas ratio, components and composition, which is considered to be the end of shale core saturation. According to the experience of the inventor, to achieve this purpose, the displacement multiple is usually more than 10PV.

[0036] The above description is only a preferred embodiment of the present invention and does not constitute any form of limitation to the present invention. Although the present invention has been disclosed as a preferred embodiment as above, it is not intended to limit the present invention. Any technician familiar with the profession can make some changes or modifications to equivalent embodiments of equivalent changes using the technical contents disclosed above without departing from the scope of the technical solution of the present invention. However, any simple modification, equivalent change and modification made to the above embodiments based on the technical essence of the present invention without departing from the content of the technical solution of the present invention still falls within the scope of the technical solution of the present invention.

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. Take degassed crude oil and associated gas from the target area, and prepare the degassed crude oil and associated gas into formation gas-bearing crude oil, and obtain the critical condensation temperature of the formation gas-bearing crude oil; S2. Obtaining a core of shale in a target area and obtaining the pore volume of the core; S3, evacuate the shale core, and when the vacuum reaches the first threshold, continue evacuating 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 gas-bearing crude oil and the core to above the critical condensation temperature of the formation gas-bearing crude oil, and displacing the core with the formation gas-bearing crude oil, with the displacement multiple being greater than 10 times the pore volume; S5. Keep the core pressure unchanged, cool the formation gas-bearing crude oil and core temperature to the reservoir temperature, and then use the formation gas-bearing crude oil to displace the core, with the displacement multiple 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-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, characterized in that 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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