A method of modeling the filling of a crude oil in a microbial rock

Abstract

The present application relates to a kind of simulation method of crude oil filling in microbial rock, the simulation method includes the following steps: core sample saturated formation water, its characterization to obtain the pore size distribution and water saturation in it;Using segmented constant pressure oil phase filling displacement, characterization to obtain the pore size distribution, oil-water distribution and oil saturation of each constant pressure stage;The present application uses segmented constant pressure oil phase filling displacement, so that displacement process conforms to the actual filling process of crude oil, can finely study each filling stage in the process of crude oil filling, the dynamic distribution change of oil and water and enrichment degree, further clarifies the mechanism of crude oil filling reservoir.

Description

TECHNICAL FIELD

[0001] The present application belongs to the technical field of oil exploration, and relates to a simulation method for oil charging in rock layers, in particular to a simulation method for oil charging in microbial rocks. BACKGROUND

[0002] Microbial rock is a general term for rocks formed by microorganisms or related to microorganisms, among which the most important is microbial carbonate rock, collectively referred to as microbial rock. Compared with other types of microbial carbonate rock and non-microbial carbonate rock, stromatolite and thrombolite in microbial rock have higher initial porosity and microbial organic matter abundance, which lay a material foundation for reservoir development.

[0003] For example, two sets of microbial reservoirs of late rifian and late vendian of neoproterozoic are developed in east Siberia, the porosity reaches more than 10%, and the recoverable reserves of oil and gas reach 22x10 8 t; the natural gas reserves of microbial rock reservoirs of Dengying group in Sichuan Basin are more than 100 billion cubic meters, the porosity reaches 6-12%; the porosity of microbial rock reservoirs in the western region of Qaidam Basin is 7-15%, and the permeability is generally greater than 1mD. It can be seen that microbial rock is an important oil and gas reservoir.

[0004] Oil and gas charging is a relatively direct way in the process of oil and gas accumulation research. Under the condition of pressure increase, hydrocarbon generated from source rock gradually enters the reservoir, slowly displacing underground water. Due to the difference in sample physical properties, the charging process also differs. If the sample has good physical properties, the crude oil can fill the whole core during the charging process; if the sample is relatively dense, it is difficult for the crude oil to be injected into the core.

[0005] Due to the high permeability of sandstone reservoirs, liquid and gas phases are easy to flow in the reservoirs, and the charging time is short. Therefore, the current oil and gas charging research mainly focuses on sandstone reservoirs. Carbonate rock reservoirs are too dense, and only rock bodies that meet the critical conditions for accumulation can accumulate. Therefore, the oil and gas charging research of carbonate rock reservoirs in the field is less, and even if the research is conducted, it is carried out by directly charging under high pressure, ignoring the process change of charging dense reservoir samples.

[0006] However, for carbonate rock reservoirs with high density, there is a problem of insufficient hydrocarbon supply in actual situation, and the reservoir may not be able to reach the saturation of charging. Therefore, the method of directly charging under high pressure is not conducive to the fine study of the dynamic distribution change of oil and water in the charging process of crude oil in carbonate rock reservoirs.

[0007] Therefore, it is necessary to provide a method for studying the dynamic distribution change of oil and water in the charging process of crude oil in carbonate rock reservoirs, and in particular to provide a simulation method for oil charging in microbial rocks. SUMMARY

[0008] The purpose of this invention is to provide a simulation method for crude oil charging in carbonate rock reservoirs, and more particularly, a simulation method for crude oil charging in microbial rocks. This simulation method conforms to the actual crude oil charging process, and can precisely study the dynamic distribution and enrichment of oil and water at each charging stage, further clarifying the mechanism of crude oil charging and reservoir formation. Moreover, the simulation method fully considers the influence of the actual physical properties of microbial rocks on oil and water charging, and has high applicability.

[0009] To achieve this objective, the present invention adopts the following technical solution:

[0010] This invention provides a method for simulating crude oil charging in microbial rock, the method comprising the following steps:

[0011] (1-1) Saturated formation water in core samples, characterized to obtain the pore size distribution of the water;

[0012] (2) A segmented constant pressure oil phase charging and displacement method was adopted to characterize and obtain the pore size distribution, oil-water distribution and oil saturation of each constant pressure stage.

[0013] In step (2), during the segmented constant pressure oil phase charging and displacement process, the pressure increases in segments, with each increment ranging from 1 to 25 MPa. For example, it can be 1 MPa, 5 MPa, 10 MPa, 15 MPa, 20 MPa, or 25 MPa, but is not limited to the listed values. Other unlisted values ​​within the range are also applicable. As a preferred technical solution, the pressure increases in segments, and the increment value in each segment is equal.

[0014] This invention employs segmented constant-pressure oil phase charging and displacement, making the displacement process conform to the actual crude oil charging process. It enables detailed study of the dynamic distribution and enrichment of oil and water at each charging stage during crude oil charging, further clarifying the mechanism of crude oil charging and reservoir formation.

[0015] The endpoints of each stage of the segmented constant pressure oil phase charging and displacement method described in this invention are as follows: when the displacement continues until no water is produced, the displacement of that constant pressure stage ends, and the pressure is increased to carry out the displacement of the next constant pressure stage.

[0016] Optionally, in step (1-1), the simulation method provided by the present invention further measures the water saturation by characterization.

[0017] Preferably, a first color marker is added to the formation water;

[0018] A second color marker is added to the oil phase;

[0019] The first color mark is a different color from the second color mark.

[0020] This invention adds a first color marker to the formation and a second color marker to the oil phase, and makes the first color marker different from the second color marker to facilitate the differentiation of water and oil discharged from the core sample.

[0021] For example, the first color marker includes, but is not limited to, methylene blue, the use of which can make the formation water blue.

[0022] For example, the second color mark includes, but is not limited to, oil-soluble red, the use of which enables the oil phase to be red.

[0023] Preferably, the method for characterizing the pore size distribution in step (1-1) includes measuring the NMR T2 spectrum.

[0024] Preferably, the method for characterizing water saturation in step (1-1) includes weighing.

[0025] For example, the method of obtaining water saturation by weighing in this invention is as follows: the pore volume of the core sample is measured and denoted as Vp; the volume of saturated formation water in the core sample is measured and denoted as Vw; then the water saturation is Sw = (Vw / Vp) × 100%.

[0026] Preferably, the method further includes a step of saturating the core sample with manganese water between step (1-1) and step (2):

[0027] (1-2) Saturated manganese water in core samples, characterized to obtain the pore size distribution and manganese water saturation.

[0028] The manganese water is an aqueous solution of manganese salt.

[0029] For example, the concentration of manganese salt in the manganese solution is 40 wt%.

[0030] This invention does not limit the method for transforming a core sample from a state saturated with formation water to a state saturated with manganese water; it is sufficient to replace the formation water in the core sample with manganese water. For example, pressurization is used to displace the formation water with manganese water.

[0031] In this invention, the manganese solution is an aqueous solution of manganese salt, to which a first color marker is added. By using the manganese solution, this invention shields the NMR signal of groundwater, facilitating the measurement of the NMR signal of the oil phase during subsequent segmented constant-pressure oil phase charging and displacement processes.

[0032] Preferably, the manganese salt comprises manganese dichloride.

[0033] Preferably, the method for characterizing the pore size distribution in step (1-2) includes measuring the NMR T2 spectrum.

[0034] Preferably, the method for characterizing the manganese water saturation in step (1-2) includes weighing.

[0035] For example, the method of obtaining manganese water saturation by weighing in this invention is as follows: based on the measured pore volume Vp of the core sample; the volume of saturated manganese water in the core sample is quantified and denoted as Vm; then the manganese water saturation is Sm = (Vm / Vp) × 100%.

[0036] Preferably, the method for characterizing the pore size distribution in step (2) includes measuring the NMR T2 spectrum.

[0037] Preferably, the method for characterizing the oil-water distribution in step (2) includes pseudo-color imaging.

[0038] Preferably, the method for characterizing the oil saturation in step (2) includes: recording the drainage weight at each constant pressure stage, calculating the drainage volume, and then calculating the oil saturation.

[0039] For example, the method of obtaining oil saturation in this invention is So = (Vo / Vp) × 100%.

[0040] Where Vo represents the oil-bearing volume in the core sample, and Vp represents the pore volume of the core sample.

[0041] Preferably, the simulation method further includes pretreatment of the core sample before step (1-1):

[0042] The core samples were cleaned and then dried. The dried samples were weighed and their T2 NMR spectra were measured to obtain the weight and pore size distribution of the dried samples.

[0043] This invention removes residual bitumen and salts from core samples by cleaning them, thus avoiding the adverse effects of these impurities on subsequent characterization. The cleaning method includes, but is not limited to, extraction cleaning.

[0044] After cleaning the core sample, the drying temperature is 70-80℃, for example, 70℃, 72℃, 75℃, 77℃, 78℃ or 80℃, but not limited to the listed values. Other unlisted values ​​within the range are also applicable.

[0045] Preferably, the core sample in step (1-1) has a length of 2.5-4 cm and a diameter of 2.4-2.7 cm.

[0046] To ensure smooth characterization and improve its accuracy, the length of the core sample in this invention is 2.5-4 cm, for example, 2.5 cm, 2.8 cm, 3 cm, 3.2 cm, 3.5 cm, 3.6 cm or 4 cm, but is not limited to the listed values. Other unlisted values ​​within the range are also applicable.

[0047] The diameter of the core sample of this invention is 2.4-2.7 cm, for example, it can be 2.4 cm, 2.5 cm, 2.6 cm or 2.7 cm, but is not limited to the listed values. Other unlisted values ​​within the range are also applicable.

[0048] Preferably, the simulation method includes the following steps:

[0049] (1-1) The core sample was cleaned and then dried. The dried sample was weighed and its T2 NMR spectrum was measured to obtain the weight and pore size distribution of the dried sample. The core sample was then saturated with formation water and characterized to obtain the pore size distribution and water saturation of the water. The pore size distribution was characterized by measuring the T2 NMR spectrum, and the water saturation was characterized by weighing.

[0050] The method for obtaining water saturation by weighing is as follows: measure the pore volume of the core sample, denoted as Vp; measure the volume of saturated formation water in the core sample, denoted as Vw; then the water saturation is Sw = (Vw / Vp) × 100%.

[0051] (1-2) Saturated manganese water in core samples is characterized to obtain the pore size distribution and manganese water saturation; the pore size distribution is characterized by measuring the nuclear magnetic resonance T2 spectrum, and the manganese water saturation is characterized by weighing.

[0052] The method for obtaining manganese water saturation by weighing is as follows: Based on the measured pore volume Vp of the core sample; quantify the volume of saturated manganese water in the core sample, denoted as Vm; then the manganese water saturation is Sm=(Vm / Vp)×100%.

[0053] (2) A segmented constant-pressure oil phase charging and displacement method was adopted to characterize and obtain the pore size distribution, oil-water distribution and oil saturation of each constant-pressure stage; the characterization method of the pore size distribution includes measuring the nuclear magnetic T2 spectrum, the characterization method of the oil-water distribution includes pseudo-color imaging, and the characterization method of the oil saturation includes recording the effluent weight of each constant-pressure stage, calculating the effluent volume, and then calculating the oil saturation.

[0054] The method for characterizing oil saturation includes: recording the weight of the drained water at each constant pressure stage, calculating the drained water volume, and then calculating the oil saturation.

[0055] In step (2), during the segmented constant pressure oil phase charging and displacement process, the pressure increases in segments, and the pressure increase value is 1-25 MPa.

[0056] A first color marker is added to the formation water, and a second color marker is added to the oil phase; the first color marker and the second color marker are different colors.

[0057] The core samples were 2.5-4 cm in length and 2.4-2.7 cm in diameter.

[0058] Compared with the prior art, the present invention has the following beneficial effects:

[0059] This invention employs segmented constant-pressure oil phase charging and displacement, making the displacement process conform to the actual crude oil charging process. It enables detailed study of the dynamic distribution and enrichment of oil and water at each charging stage during crude oil charging, further clarifying the mechanism of crude oil charging and reservoir formation. Attached Figure Description

[0060] Figure 1 Aperture distribution diagrams for each stage of the simulation method provided in Example 1;

[0061] Figure 2 A schematic diagram of the outflow weight at each constant pressure stage in the simulation method provided in Example 1;

[0062] Figure 3 A schematic diagram of oil saturation at each constant pressure stage in the simulation method provided in Example 1;

[0063] Figure 4 The pseudo-color image during the displacement process in the simulation method provided in Example 1. Detailed Implementation

[0064] The technical solution of the present invention will be further illustrated below through specific embodiments. Those skilled in the art should understand that the embodiments described are merely illustrative of the present invention and should not be construed as limiting the invention in any way.

[0065] In a specific embodiment of the present invention, the microbial rock is a microbial carbonate rock, and the core sample used is a core sample of the microbial rock, which originates from the N1 stratum in the Honggouzi area of ​​the Qaidam Basin.

[0066] Example 1

[0067] This embodiment provides a simulation method for crude oil charging in microbial rock, the simulation method including the following steps:

[0068] (1-1) The core sample was cleaned and then dried at 75°C. The dried sample was weighed and its T2 NMR spectrum was measured to obtain the weight and pore size distribution. The core sample was then saturated with formation water and characterized to obtain the pore size distribution and water saturation of the water. The pore size distribution was characterized by measuring the T2 NMR spectrum, and the water saturation was characterized by weighing.

[0069] Add methylene blue to formation water;

[0070] The method for obtaining water saturation by weighing is as follows: measure the pore volume of the core sample, denoted as Vp; measure the volume of saturated formation water in the core sample, denoted as Vw; then the water saturation is Sw = (Vw / Vp) × 100%.

[0071] (1-2) Saturated manganese water in core samples is characterized to obtain the pore size distribution and manganese water saturation; the pore size distribution is characterized by measuring the nuclear magnetic resonance T2 spectrum, and the manganese water saturation is characterized by weighing.

[0072] The manganese solution is an aqueous solution of manganese chloride, with a concentration of 40 wt% manganese chloride in the manganese solution, and methylene blue is added to the manganese solution;

[0073] The method for obtaining manganese water saturation by weighing is as follows: Based on the measured pore volume Vp of the core sample; quantify the volume of saturated manganese water in the core sample, denoted as Vm; then the manganese water saturation is Sm=(Vm / Vp)×100%.

[0074] (2) A segmented constant pressure oil phase charging and displacement method was adopted to characterize and obtain the pore size distribution, oil-water distribution and oil saturation of each constant pressure stage; the characterization method of the pore size distribution includes measuring the nuclear magnetic T2 spectrum, the characterization method of the oil-water distribution includes pseudo-color imaging, and the characterization method of the oil saturation includes recording the weight of the effluent at each constant pressure stage and then calculating the oil saturation.

[0075] The method for characterizing the oil saturation includes: recording the drainage weight at each constant pressure stage, calculating the drainage volume, and then calculating the oil saturation.

[0076] In step (2), during the segmented constant pressure oil phase charging and displacement process, the pressure increases in segments, namely 5MPa, 10MPa, 15MPa, 20MPa and 25MPa.

[0077] The formation water is treated with a first color marker, methylene blue, and the oil phase is treated with a second color marker, oil-soluble red; the oil phase is fluorinated oil.

[0078] The core sample was 3.5 cm long and 2.5 cm in diameter.

[0079] In this embodiment, the pore size distribution of the obtained dry sample, the pore size distribution of saturated formation water, the pore size distribution of saturated manganese water, and the pore size distribution at each constant pressure stage are as follows: Figure 1 As shown, Figure 1 In the diagram, the x-axis represents the orifice radius, and the y-axis represents the fluid signal amplitude. A larger fluid signal amplitude indicates a larger fluid volume. Figure 1The distribution and signal intensity of residual water in the dry sample, the distribution and signal intensity of water when the formation water is saturated, the distribution and signal intensity of manganese water after manganese water saturation, and the distribution and signal intensity of oil after oil-driven manganese water at 5MPa, 10MPa, 15MPa, 20MPa, and 25MPa are known.

[0080] During the segmented constant-pressure oil phase charging and displacement process, the endpoint of each constant-pressure stage is the point at which water ceases to be discharged. The weight of the effluent at each constant-pressure stage is recorded using an analytical balance with a concentration of 0.01 g / mL (e.g., 0.01 g / mL). Figure 2 As shown), and calculate the saturation content (e.g.) in each constant pressure stage. Figure 3 (As shown).

[0081] During the displacement process, pseudo-color imaging at each constant pressure stage is as follows: Figure 4 As shown, by Figure 4 The migration direction and distribution characteristics of oil and water can be observed. Column (a) shows the pseudo-color image of manganese-saturated water, column (b) shows the pseudo-color image of oil at 5 MPa pressure, column (c) shows the pseudo-color image of oil at 10 MPa pressure, column (d) shows the pseudo-color image of oil at 15 MPa pressure, column (e) shows the pseudo-color image of oil at 20 MPa pressure, and column (f) shows the pseudo-color image of oil at 25 MPa pressure. Figure 4 This shows the distribution of oil in the core after injection under different pressures.

[0082] In summary, this invention employs segmented constant-pressure oil phase charging and displacement, making the displacement process conform to the actual crude oil charging process. This allows for a detailed study of the dynamic distribution and enrichment of oil and water at each charging stage during crude oil charging, further clarifying the mechanism of crude oil charging and reservoir formation.

[0083] The above description is only a specific embodiment of the present invention, but the protection scope of the present invention is not limited thereto. Those skilled in the art should understand that any changes or substitutions that can be easily conceived by those skilled in the art within the technical scope disclosed in the present invention fall within the protection and disclosure scope of the present invention.

Claims

1. A method for simulating crude oil charging in microbial rock, characterized in that, The simulation method includes the following steps: (1-1) Clean the core sample and then dry it. Weigh the dried sample and measure the nuclear magnetic resonance T2 spectrum to obtain the weight and pore size distribution of the dried sample. The core sample is saturated with formation water and is characterized to obtain the pore size distribution and water saturation of the water. (1-2) Saturated manganese water in core samples, characterized to obtain the pore size distribution and manganese water saturation; (2) A segmented constant pressure oil phase charging and displacement method was adopted to characterize the pore size distribution, oil-water distribution and oil saturation of each constant pressure stage. In step (2), during the segmented constant pressure oil phase charging and displacement process, the pressure increases in segments, and the pressure increase value is 1-25 MPa. A first color marker is added to the formation water; a second color marker is added to the oil phase; the first color marker and the second color marker are different colors.

2. The simulation method according to claim 1, characterized in that, The method for characterizing the pore size distribution in step (1-1) includes measuring the NMR T2 spectrum.

3. The simulation method according to claim 1, characterized in that, The method for characterizing water saturation in step (1-1) includes weighing.

4. The simulation method according to claim 1, characterized in that, The manganese water is an aqueous solution of manganese salt.

5. The simulation method according to claim 4, characterized in that, The manganese salt includes manganese dichloride.

6. The simulation method according to claim 1, characterized in that, The method for characterizing the pore size distribution described in steps (1-2) includes measuring the NMR T2 spectrum.

7. The simulation method according to claim 1, characterized in that, The method for characterizing the manganese water saturation in step (1-2) includes weighing.

8. The simulation method according to claim 1, characterized in that, The method for characterizing the pore size distribution in step (2) includes measuring the NMR T2 spectrum.

9. The simulation method according to claim 1, characterized in that, The oil-water distribution characterization method in step (2) includes pseudo-color imaging.

10. The simulation method according to claim 1, characterized in that, The method for characterizing oil saturation in step (2) includes: recording the weight of the outflowing water at each constant pressure stage, calculating the volume of the outflowing water, and then calculating the oil saturation.

11. The simulation method according to claim 1, characterized in that, The core sample in step (1-1) has a length of 2.5-4 cm and a diameter of 2.4-2.7 cm.

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