Simulation method for filling crude oil in microbial rock

Abstract

The invention relates to a simulation method for filling crude oil in microbial rock, which comprises the following steps: saturating formation water in a rock core sample, and characterizing the saturated formation water to obtain the pore size distribution and water saturation of the water in the saturated formation water; adopting sectional type constant-pressure oil phase filling displacement and characterization to obtain pore size distribution, oil-water distribution and oil saturation of each constant-pressure stage; according to the method, sectional type constant-pressure oil phase filling displacement is adopted, so that the displacement process conforms to the actual filling process of crude oil, the dynamic distribution change and the enrichment degree of oil and water in each filling stage in the filling process of the crude oil can be finely researched, and the mechanism of filling and reservoir forming of the crude oil is further clarified.

Description

Technical Field

[0001] The invention belongs to the technical field of petroleum exploration, and relates to a simulation method for crude oil filling in a rock formation, and in particular to a simulation method for crude oil filling in a microbial rock. Background Art

[0002] Microbial rocks are a general term for rocks formed by microorganisms or related to microorganisms. The most important of these are microbial carbonate rocks, collectively referred to as microbial rocks. Compared with other types of microbial carbonate rocks and non-microbial carbonate rocks, stromatolites and thrombolites in microbial rocks have higher initial porosity and microbial organic matter abundance, laying a material foundation for reservoir development.

[0003] For example, the Neoproterozoic in East Siberia developed two sets of microbial reservoirs in the Late Riphic and Late Vendian periods, with porosities exceeding 10% and recoverable oil and gas reserves of 22×10 8 t; The natural gas reserves of the Dengying Formation microbial reservoir in the Sichuan Basin are over 1 trillion cubic meters, with a porosity of 6-12%; the porosity of the microbial reservoir in the western part of the Qaidam Basin is 7-15%, and the permeability is generally greater than 1mD. It can be seen that microbial rock is an important type of oil and gas reservoir.

[0004] Oil and gas charging is a relatively direct method in the process of oil and gas accumulation research. Under the condition of supercharging, hydrocarbons are generated in source rocks, and oil and gas gradually enter the reservoir from the source rocks, slowly displacing groundwater. Due to the different physical properties of the samples themselves, there are also differences in the charging process. If the physical properties of the sample are good, the crude oil can fill the entire core during the charging process; if the sample is relatively dense, it will be difficult to inject crude oil into the core.

[0005] Since sandstone reservoirs have high permeability, liquid and gas phases are easy to flow in the reservoirs and the filling time is short, the current oil and gas filling research is mainly focused on sandstone reservoirs. Carbonate reservoirs are too dense, and only rock masses that meet the critical conditions for reservoir formation can form reservoirs. Therefore, there are few studies on oil and gas filling in carbonate reservoirs in this field. Even if there are studies, they are carried out by direct filling under high pressure, ignoring the process changes of filling dense reservoir samples.

[0006] However, for carbonate reservoirs with higher density, there is actually a problem of insufficient hydrocarbon supply, and the reservoir may not reach saturation. Therefore, the direct filling method under high pressure is not conducive to the detailed study of the dynamic distribution changes of oil and water during the filling process of crude oil in carbonate reservoirs.

[0007] Therefore, it is necessary to provide a method for studying the dynamic distribution changes of oil and water during the filling process of crude oil in carbonate reservoirs, and in particular, it is necessary to provide a simulation method for the filling of crude oil in microbial rocks. Summary of the invention

[0008] The purpose of the present invention is to provide a simulation method for crude oil charging in carbonate rock reservoirs, and in particular to provide a simulation method for crude oil charging in microbial rock. The simulation method is consistent with the actual crude oil charging process, and can finely study the dynamic distribution changes and enrichment levels of oil and water in each charging stage during the crude oil charging process, and further clarify the mechanism of crude oil charging and accumulation; moreover, the simulation method fully considers the influence of the actual physical properties of microbial rock on oil and water charging, and has high applicability.

[0009] In order to achieve the purpose of the invention, the present invention adopts the following technical solutions:

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

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

[0012] (2) Using segmented constant pressure oil phase filling displacement, characterization is performed to obtain the pore size distribution, oil-water distribution, and oil saturation at each constant pressure stage;

[0013] In the step (2) of the stepwise constant pressure oil phase filling and displacement process, the pressure is increased stepwise, and the pressure increase value is 1-25MPa, for example, it can be 1MPa, 5MPa, 10MPa, 15MPa, 20MPa or 25MPa, but it is not limited to the listed values, and other values ​​not listed in the numerical range are also applicable. As a preferred technical solution, the pressure is increased stepwise, and the value of each step increase is equal.

[0014] The present invention adopts segmented constant pressure oil phase filling displacement, so that the displacement process conforms to the actual crude oil filling process, and can finely study the dynamic distribution changes and enrichment degree of oil and water in each filling stage during the crude oil filling process, and further clarify the mechanism of crude oil filling accumulation.

[0015] The end points of each stage of the segmented constant pressure oil phase filling displacement described in the present invention are: when the displacement stops until water is discharged, the displacement of the constant pressure stage ends, and the pressure is increased to carry out the displacement of the next constant pressure stage.

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

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

[0018] Adding a second color marker to the oil phase;

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

[0020] The present invention adds a first color marker to the formation, adds a second color marker to the oil phase, and makes the first color marker different from the second color marker, so as to facilitate the distinction between water and oil discharged from the core sample.

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

[0022] Exemplarily, the second color mark includes, but is not limited to, oil-soluble red. The use of oil-soluble red can make the color of the oil phase red.

[0023] Preferably, the method for characterizing the pore size distribution in step (1-1) comprises measuring the nuclear magnetic resonance T2 spectrum.

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

[0025] Exemplarily, the method of obtaining water saturation by weighing in the present invention is: measuring the pore volume of the core sample, recorded as Vp; measuring the volume of saturated formation water in the core sample, recorded as Vw; then the water saturation is Sw = (Vw / Vp) × 100%.

[0026] Preferably, the method further comprises the 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, characterizing them to obtain the pore size distribution and manganese water saturation of the manganese water;

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

[0029] Exemplarily, the concentration of manganese salt in the manganese water is 40 wt %.

[0030] The present invention does not limit the method of converting the core sample from a saturated formation water state to a saturated manganese water state, as long as the formation water in the core sample is replaced by manganese water. Exemplarily, the displacement of formation water by manganese water is performed by pressurization.

[0031] In the present invention, the manganese water is an aqueous solution of manganese salt, and the first color mark is added to the manganese water. The present invention shields the nuclear magnetic signal of groundwater by using manganese water, which is convenient for the determination of the oil phase nuclear magnetic signal in the subsequent segmented constant pressure oil phase filling and displacement process.

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

[0033] Preferably, the method for characterizing the pore size distribution in step (1-2) comprises measuring the nuclear magnetic resonance T2 spectrum.

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

[0035] Exemplarily, the method of obtaining manganese water saturation by weighing in the present invention is: based on the measured pore volume Vp of the core sample; quantifying the volume of saturated manganese water in the core sample, recorded 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) comprises measuring the nuclear magnetic resonance T2 spectrum.

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

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

[0039] Exemplarily, the method for obtaining the oil saturation in the present invention is So=(Vo / Vp)×100%.

[0040] Wherein, 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 comprises pre-processing the core sample before step (1-1):

[0042] The core sample was cleaned and then dried. The obtained dry sample was weighed and the nuclear magnetic resonance T2 spectrum was measured to obtain the dry sample weight and pore size distribution.

[0043] The present invention can remove impurities such as asphaltene and salts remaining in the core sample by cleaning the core sample, thereby avoiding the adverse effects of the impurity components 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°C, for example, 70°C, 72°C, 75°C, 77°C, 78°C or 80°C, but is not limited to the listed values, and other values ​​not listed within the numerical 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] In order to smoothly carry out the characterization and improve the accuracy of the characterization, the length of the core sample of the present invention is 2.5-4 cm, for example, it can be 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, and other unlisted values ​​within the numerical range are also applicable.

[0047] The diameter of the core sample of the present 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 it is not limited to the listed values, and other values ​​not listed within the numerical range are also applicable.

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

[0049] (1-1) washing the core sample, drying it, weighing the obtained dry sample and measuring the nuclear magnetic T2 spectrum to obtain the weight and pore size distribution of the dry sample; then saturating the formation water in the core sample and characterizing it to obtain the pore size distribution and water saturation of the water therein; the characterization method of the pore size distribution includes measuring the nuclear magnetic T2 spectrum, and the characterization method of the water saturation includes weighing;

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

[0051] (1-2) characterizing saturated manganese water in a core sample to obtain the pore size distribution and manganese water saturation of the manganese water; the characterization method of the pore size distribution comprises measuring a nuclear magnetic resonance T2 spectrum, and the characterization method of the manganese water saturation comprises weighing;

[0052] The method of obtaining the manganese water saturation by weighing is as follows: according to the measured pore volume Vp of the core sample; the volume of saturated manganese water in the core sample is quantified, recorded as Vm; then the manganese water saturation is Sm = (Vm / Vp) × 100%;

[0053] (2) using segmented constant pressure oil phase filling displacement 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 resonance 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 water output weight of each constant pressure stage, calculating the drainage volume, and then calculating the oil saturation;

[0054] The characterization method of oil saturation includes: recording the weight of drainage at each constant pressure stage, calculating the drainage volume, and then calculating the oil saturation;

[0055] During the stepwise constant pressure oil phase filling and displacement process in step (2), the pressure increases stepwise, 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 have different colors;

[0057] The core samples have a length of 2.5-4 cm and a diameter of 2.4-2.7 cm.

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

[0059] The present invention adopts segmented constant pressure oil phase filling displacement, so that the displacement process conforms to the actual crude oil filling process, and can finely study the dynamic distribution changes and enrichment degree of oil and water in each filling stage during the crude oil filling process, and further clarify the mechanism of crude oil filling accumulation. BRIEF DESCRIPTION OF THE DRAWINGS

[0060] Figure 1 A pore size distribution diagram of each stage in the simulation method provided in Example 1;

[0061] Figure 2 A schematic diagram of the water output 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 This is a pseudo-color image of the displacement process in the simulation method provided in Example 1. DETAILED DESCRIPTION

[0064] The technical solution of the present invention is further described below by specific implementation methods. It should be understood by those skilled in the art that the embodiments are only to help understand the present invention and should not be regarded as specific limitations of the present invention.

[0065] In a specific implementation manner 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, and the source of the microbial rock is the N1 formation 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 comprising the following steps:

[0068] (1-1) washing the core sample, drying it at 75° C., weighing the obtained dry sample and measuring the nuclear magnetic resonance T2 spectrum to obtain the weight and pore size distribution of the dry sample; then saturating the formation water in the core sample and characterizing it to obtain the pore size distribution and water saturation of the water therein; the characterization method of the pore size distribution includes measuring the nuclear magnetic resonance T2 spectrum, and the characterization method of the water saturation includes weighing;

[0069] Methyl blue was added to the formation water;

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

[0071] (1-2) characterizing saturated manganese water in a core sample to obtain the pore size distribution and manganese water saturation of the manganese water; the characterization method of the pore size distribution comprises measuring a nuclear magnetic resonance T2 spectrum, and the characterization method of the manganese water saturation comprises weighing;

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

[0073] The method of obtaining the manganese water saturation by weighing is as follows: according to the measured pore volume Vp of the core sample; the volume of saturated manganese water in the core sample is quantified, recorded as Vm; then the manganese water saturation is Sm = (Vm / Vp) × 100%;

[0074] (2) using segmented constant pressure oil phase filling displacement 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 resonance 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 water weight of 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] During the stepwise constant pressure oil phase filling and displacement process in step (2), the pressure increases stepwise to 5 MPa, 10 MPa, 15 MPa, 20 MPa and 25 MPa respectively;

[0077] The first color marker methyl blue is added to the formation water, and the second color marker oil-soluble red is added to the oil phase; the oil phase is fluorinated oil.

[0078] The core sample has a length of 3.5 cm and a diameter of 2.5 cm.

[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 of each constant pressure stage are as follows: Figure 1 As shown, Figure 1 The x-axis is the channel radius, and the y-axis is the fluid signal amplitude. The larger the fluid signal amplitude, the larger the amount of fluid. Figure 1It can be known that the distribution and signal intensity of residual water in the dry sample, the distribution and signal intensity of water when saturated with formation water, the distribution and signal intensity of manganese water after saturated manganese water, the distribution and signal intensity of oil after 5MPa oil-driven manganese water, 10MPa oil-driven manganese water, 15MPa oil-driven manganese water, 20MPa oil-driven manganese water, and 25MPa oil-driven manganese water.

[0080] During the segmented constant pressure oil phase filling and displacement process, the end point of each constant pressure stage is the displacement until no water is discharged. The weight of the discharged water in each constant pressure stage is recorded using a 1 / 10,000 analytical balance (e.g. Figure 2 ), and calculate the saturation of each constant pressure stage (as shown in Figure 3 shown).

[0081] During the displacement process, pseudo-color images of each constant pressure stage are shown in Figure 2. Figure 4 As shown by Figure 4 The migration direction and distribution characteristics of oil and water can be seen, among which (a) is a pseudo-color image of saturated manganese water, (b) is a pseudo-color image of oil under 5MPa pressure, (c) is a pseudo-color image of oil under 10MPa pressure, (d) is a pseudo-color image of oil under 15MPa pressure, (e) is a pseudo-color image of oil under 20MPa pressure, and (f) is a pseudo-color image of oil under 25MPa pressure. Figure 4 It can be known that the distribution of oil in the core after filling under different pressures.

[0082] In summary, the present invention adopts segmented constant pressure oil phase injection displacement, so that the displacement process conforms to the actual crude oil injection process, and can finely study the dynamic distribution changes and enrichment degree of oil and water in each injection stage during the crude oil injection process, and further clarify the mechanism of crude oil injection accumulation.

[0083] The above description is only a specific implementation mode 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 thought of by those skilled in the art within the technical scope disclosed by the present invention are within the protection scope and disclosure scope of the present invention.

Claims

1. A method for simulating the injection of crude oil into microbial rock, characterized in that: The simulation method comprises the following steps: (1-1) Saturated formation water in core samples, characterizing them to obtain the pore size distribution of water therein; (2) Using segmented constant pressure oil phase filling displacement, characterization is performed to obtain the pore size distribution, oil-water distribution, and oil saturation at each constant pressure stage; During the segmented constant pressure oil phase filling and displacement process in step (2), the pressure increases segment by segment, and the pressure increase value is 1-25 MPa.

2. The simulation method according to claim 1, characterized in that: adding a first color marker to the formation water; Adding a second color marker to the oil phase; The first color mark is different from the second color mark in color.

3. The simulation method according to claim 1 or 2, characterized in that: The method for characterizing the pore size distribution in step (1-1) comprises measuring a nuclear magnetic resonance T2 spectrum; Preferably, the method for characterizing the water saturation in step (1-1) includes weighing.

4. The simulation method according to any one of claims 1 to 3, characterized in that: The method further comprises the step of saturating the core sample with manganese water between step (1-1) and step (2): (1-2) Saturated manganese water in core samples, characterizing them to obtain the pore size distribution and manganese water saturation of the manganese water; 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 4 or 5, characterized in that: The method for characterizing the pore size distribution in step (1-2) comprises measuring the nuclear magnetic resonance T2 spectrum; Preferably, the method for characterizing the manganese water saturation in step (1-2) includes weighing.

7. The simulation method according to any one of claims 1 to 6, characterized in that: The method for characterizing the pore size distribution in step (2) comprises measuring a nuclear magnetic resonance T2 spectrum; Preferably, the method for characterizing the oil-water distribution in step (2) comprises pseudo-color imaging; Preferably, the method for characterizing the oil saturation in step (2) comprises: recording the weight of the discharged water in each constant pressure stage, calculating the discharged water volume, and then calculating the oil saturation.

8. The simulation method according to any one of claims 1 to 7, characterized in that: The simulation method further comprises, before step (1-1), pre-processing the core sample: The core sample was cleaned and then dried. The obtained dry sample was weighed and the nuclear magnetic resonance T2 spectrum was measured to obtain the dry sample weight and pore size distribution.

9. The simulation method according to any one of claims 1 to 8, 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.

10. The simulation method according to claim 1, characterized in that: The simulation method comprises the following steps: (1-1) washing the core sample, drying it, weighing the obtained dry sample and measuring the nuclear magnetic T2 spectrum to obtain the weight and pore size distribution of the dry sample; then saturating the formation water in the core sample and characterizing it to obtain the pore size distribution and water saturation of the water therein; the characterization method of the pore size distribution includes measuring the nuclear magnetic T2 spectrum, and the characterization method of the water saturation includes weighing; (1-2) characterizing saturated manganese water in a core sample to obtain the pore size distribution and manganese water saturation of the manganese water; the characterization method of the pore size distribution comprises measuring a nuclear magnetic resonance T2 spectrum, and the characterization method of the manganese water saturation comprises weighing; (2) Using segmented constant pressure oil phase filling displacement, characterization is performed to obtain the pore size distribution, oil-water distribution, and oil saturation at 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 water weight at each constant pressure stage, calculating the drainage volume, and then calculating the oil saturation; During the stepwise constant pressure oil phase filling and displacement process in step (2), the pressure increases stepwise, and the pressure increase value is 1-25 MPa; 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 have different colors; The core samples have a length of 2.5-4 cm and a diameter of 2.4-2.7 cm.

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