Shale reservoir physical property and oiliness controlled factor analysis method

Abstract

The invention belongs to the technical field of unconventional shale oil and gas exploration and development, and discloses a shale reservoir physical property and oiliness controlled factor analysis method. Comprising the following steps: determining a reservoir classification standard through a one-dimensional nuclear magnetic experiment and a mercury injection experiment phase; and performing lithogenous phase statistics on the pore ratio and effective porosity controlled factor analysis. And analyzing fluid properties of different lithofacies based on two-dimensional nuclear magnetic oiliness explanation. And analyzing oiliness controlled factors. By analyzing the controlled factors of the physical property and oiliness of the shale reservoir, the sweet spot distribution can be determined, the shale oil momentum can be determined, and the shale oil productivity can be improved.

Description

Technical Field

[0001] The present invention belongs to the technical field of unconventional shale oil and gas exploration and development, and relates to a method for analyzing controlled factors of shale reservoir physical properties and oil content. Background Art

[0002] Shale oil and gas is the focus of unconventional exploration in all countries of the world. my country has abundant shale oil resources in its shale reservoirs, and logging technology plays an important role in exploration and development.

[0003] There are differences between unconventional and conventional reservoirs, and the relationship between physical properties and oil content is not a simple one-to-one correspondence. Therefore, it is urgent to develop a method for analyzing the controlled factors of shale reservoir physical properties and oil content to meet the current working conditions. Summary of the invention

[0004] In order to overcome the shortcomings of the prior art, the present invention provides a method for analyzing the controlled factors of shale reservoir physical properties and oil content. The controlled factors of shale reservoir physical properties and oil content are analyzed to clarify the distribution of sweet spots, clarify the movable amount of shale oil, and improve the production capacity of shale oil.

[0005] The above object of the present invention is achieved through the following technical solutions:

[0006] A method for analyzing controlled factors of shale reservoir physical properties and oil content, comprising the following steps:

[0007] Step 1: Determine the reservoir classification standard through one-dimensional nuclear magnetic resonance experiments and mercury injection experiments.

[0008] Step 2: Analyze the porosity percentage and controlling factors of effective porosity by lithofacies.

[0009] Step 3: Analyze the fluid properties of different lithofacies based on 2D NMR oil-bearing interpretation.

[0010] Step 4: Analysis of controlled factors of oil content.

[0011] The application of the above-mentioned analysis method of factors controlling shale reservoir physical properties and oil content in the Daqingzijing area.

[0012] The beneficial effects of the present invention compared with the prior art are:

[0013] The present invention provides a method for analyzing the controlled factors of shale reservoir physical properties and oil content. The method is highly operable and can analyze the controlled factors of shale reservoir physical properties and oil content through a variety of experiments. It is of great significance for clarifying the main controlling factors of shale oil micropores, establishing oil content classification evaluation standards, and revealing the main controlling factors of shale oil production capacity. BRIEF DESCRIPTION OF THE DRAWINGS

[0014] In order to more clearly illustrate the technical solutions in the present invention or related technologies, the following briefly introduces the drawings required for use in the embodiments or related technical descriptions. Obviously, the drawings described below are some embodiments of the present invention. For ordinary technicians in this field, other drawings can be obtained based on these drawings without paying creative work.

[0015] Figure 1 Fractal characteristic diagram of mercury injection of shale samples; Figure (a) is the mercury injection curve diagram of sample No. 12 in Well A, Figure (b) is the fractal characteristic diagram of sample No. 12 in Well A, Figure (c) is the mercury injection curve diagram of sample No. 2 in Well B, and Figure (d) is the fractal characteristic diagram of sample No. 2 in Well B.

[0016] Figure 2 Shale reservoir space classification diagram;

[0017] Figure 3 Figure 2. Relationship between the proportion of medium and large pores and each porosity in shale oil samples; Figure (a) is the relationship between the proportion of medium and large pores and the total porosity, Figure (b) is the relationship between the proportion of medium and large pores and the effective porosity, Figure (c) is the relationship between the proportion of medium and large pores and the total movable fluid porosity, and Figure (d) is the relationship between the proportion of medium and large pores and the centrifugal movable fluid porosity.

[0018] Figure 4 Distribution range of hydrocarbon content in different lithofacies and different occurrence states; in the figure, A is high-organic mud-grade laminated clay shale, B is medium-high organic mud-grade laminated felsic shale, C is medium-low organic silt-laminated shale, D is medium-low organic massive mudstone, E is silty mudstone, F is siltstone, and G is limestone. Figure (a) is the distribution range of NMR free oil content, Figure (b) is the distribution range of NMR adsorbed oil content, Figure (c) is the distribution range of NMR total oil content, and Figure (d) is the distribution range of free proportion.

[0019] Figure 5 Relationship diagram between TOC, NMR free oil content and NMR effective porosity of the shale in the first member of Daqingzijingqing Formation.

[0020] Figure (a) shows the relationship between TOC and NMR free oil content, and Figure (b) shows the relationship between TOC and NMR effective porosity. DETAILED DESCRIPTION

[0021] The technical solution of the present invention will be described clearly and completely below in conjunction with the accompanying drawings. Obviously, the described embodiments are only part of the embodiments of the present invention, not all of the embodiments. Based on the embodiments of the present invention, all other embodiments obtained by ordinary technicians in this field without creative work are within the scope of protection of the present invention.

[0022] The present invention is described in detail below by specific examples, but the protection scope of the present invention is not limited. Unless otherwise specified, the experimental methods used in the present invention are all conventional methods, and the experimental equipment, materials, reagents, etc. used can be obtained from commercial channels.

[0023] In the description of the present invention, it should be noted that the terms "vertical", "horizontal", "inside", "outside" and the like indicate positions or positional relationships based on the positions or positional relationships shown in the drawings, and are only for the convenience of describing the present invention and simplifying the description, rather than indicating or implying that the device or component referred to must have a specific position, be constructed and operated in a specific position, and therefore cannot be understood as limiting the present invention. In addition, the terms "first", "second", and "third" are only used for distinction, and cannot be understood as indicating or implying relative importance.

[0024] In addition, the technical features involved in the different embodiments of the present invention described below can be combined with each other as long as they do not conflict with each other.

[0025] In order to make the objectives, technical solutions and advantages of the present invention more clear, the embodiments of the present invention will be further described in detail below with reference to the accompanying drawings.

[0026] Example 1

[0027] A method for analyzing controlled factors of shale reservoir physical properties and oil content, comprising the following steps:

[0028] Step 1: Determine the reservoir classification standard by combining one-dimensional nuclear magnetic resonance experiments and mercury injection experiments.

[0029] A fractal is usually defined as a rough or fragmentary geometric shape that can be divided into several parts, and each part is (at least approximately) a reduced version of the whole shape, that is, it has self-similar characteristics. Based on fractal theory, the mercury saturation S Hg and capillary pressure p c There is a relationship between the fractal dimension D and the following: lg(1-S Hg )=(D-3)lgp c -(D-3)lgp cmin

[0030] Where: S Hg is mercury saturation, %; p cmin is the capillary pressure corresponding to the maximum pore throat radius, MPa, which is a constant. The mercury injection curves of 30 shale samples from Well A and Well B of the Qing 1st Member in the Daqingzijing area were fractally studied ( Figure 1), it was found that the mercury injection curve showed multi-segment fractal characteristics, and the fractal fitting accuracy of each segment was above 90%, indicating that the pore space of the shale reservoir has multiple fractal characteristics, and the fractal inflection points are located near 1.37MPa, 13.77MPa, and 48MPa, corresponding to pore throat diameters of about 1000nm, 100nm, and 30nm. The pore throats in the same fractal interval correspond to the same fractal dimension, while the fractal dimensions between different intervals vary greatly, corresponding to different pore throat types and combination relationships. Therefore, based on the above fractal inflection points, the shale reservoir space can be divided into four parts: micropores (pore diameter <30nm), small pores (30-100nm), medium pores (100-1000nm), and large pores (>1000nm) ( Figure 2 ).

[0031] Step 2: Analyze the porosity percentage and controlling factors of effective porosity by lithofacies.

[0032] The movable volume of fluid under certain pressure difference conditions is obtained through the cutoff value of nuclear magnetic resonance logging, or through centrifugation or displacement experiments, which corresponds to the actual movable fluid porosity. This time, a centrifuge experiment (10000r / min speed, corresponding to 3.25MPa pressure difference) was used to determine the movable fluid porosity of shale oil samples.

[0033] The relationship between various porosities and the proportion of medium and large pores was statistically analyzed according to different lithofacies (medium-low organic matter silt laminar shale-felsic shale, medium-high organic matter mud laminar felsic shale-clay shale). Figure 3 ), we can find the following rules:

[0034] 1) The correlation between each porosity parameter and the proportion of medium and large pores varies greatly. The total porosity and total movable fluid porosity have the worst correlation with the proportion of medium and large pores, and the centrifugal movable fluid porosity has the best correlation with medium and large pores, followed by effective porosity. It can be seen that medium and large pores mainly determine the movable fluid content of shale oil reservoirs, and have a weak relationship with the volume content of free oil and free water. This may be because a lot of free oil and free water are also present in small pores or some micropores, and the mobility of this part is weak, resulting in a weak correlation between the total movable fluid porosity and the proportion of medium and large pores.

[0035] 2) There are large differences between different lithofacies. In general, the proportion of medium and large pores in type C lithofacies and low organic matter type B lithofacies is lower than that in type B lithofacies with medium and high organic matter and type A lithofacies. However, the distribution range of effective porosity and movable fluid porosity of the two lithofacies is basically similar ( Figure 3), which also means that when the proportion of medium and large pores is the same, the centrifugal movable fluid porosity of type C lithofacies is significantly better than that of medium and high organic matter type B and type A lithofacies. This difference is mainly because the proportion of intergranular pores in type C lithofacies is relatively high. Although the proportion of medium and large pores is small, the intergranular pore throat system is relatively developed, and the proportion of medium and large pore throats is significantly higher than that of the other two lithofacies. Therefore, when the proportion of medium and large pores is the same, the corresponding centrifugal movable fluid content is significantly higher.

[0036] Through the above analysis, when classifying shale oil reservoirs, the porosity parameters can be selected from the two indicators of effective porosity and movable fluid porosity (centrifugal). For microstructural parameters, the proportion of medium and large pores can be selected. At the same time, the classification process must be based on lithofacies to establish standards, because the medium and large pore throat systems of different lithofacies are different. When the effective porosity and the proportion of medium and large pores are the same, the movable fluid porosity (centrifugal) of different lithofacies is different.

[0037] 3) Analysis of factors controlling effective porosity

[0038] Since movable fluid porosity is an important factor affecting production capacity, this time, movable fluid porosity is used as the main indicator, and the proportion of medium and large pores and effective porosity are used as auxiliary indicators to establish reservoir classification standards according to lithofacies types. The movable fluid porosity of 1%, 0.75% and 0.45% are selected as the boundaries, and the reservoirs are divided into three categories, which are further divided into two categories: C-type lithofacies-low organic matter B-type lithofacies, medium and high organic matter B-type and A-type lithofacies, and the corresponding boundaries of medium and large pore proportion and effective porosity are determined respectively.

[0039] For Class C lithofacies-low organic matter Class B lithofacies, the corresponding boundaries of macropore proportion in Class I, Class II and Class III reservoirs are 15%, 12% and 10%, and the corresponding boundaries of effective porosity are 4.15%, 3.5% and 3.2%. From Class I to Class III reservoirs, the proportion of medium pores decreases significantly and micropores increase rapidly, indicating an increase in intercrystalline pore content. In this lithofacies, Class I reservoirs are mainly developed in Class C lithofacies.

[0040] For medium-high organic matter B and A lithofacies, the corresponding boundaries of macropore proportion in Class I, Class II and Class III reservoirs are 25%, 22% and 18%, and the corresponding boundaries of effective porosity are 4.5%, 4% and 3.35%. The proportion of medium-large pores and the effective porosity boundaries are higher than those in Class C lithofacies, and the pore proportion shows a significant decrease and the micropores show a rapid increase trend. In this type of lithofacies, I reservoirs are mainly developed in Class B and Class A lithofacies.

[0041] By analyzing the pore distribution and pore throat distribution characteristics corresponding to various reservoirs in different lithofacies, it is found that for type C lithofacies, from type I reservoir to type III reservoir, in both pore distribution and pore throat distribution, the content of medium and large pores shows a decreasing trend, indicating that the proportion of large pore throats such as intergranular pores gradually decreases; for type B lithofacies, from type I reservoir to type III reservoir, the content of medium and large pores in pore distribution decreases significantly, and the content of micropores increases rapidly, indicating that large pores such as intergranular dissolution pores are gradually replaced by clay intercrystalline pores, and the proportion of large pore throats in mercury injection pore throat distribution also shows a certain decreasing trend, but it is not as obvious as type C lithofacies; for type A lithofacies, as the reservoir type deteriorates, the decreasing trend of large pore content in pore distribution is not obvious, the micropores show a rapid increasing trend, and the changing trend of large pore content in pore throat distribution is not obvious, which also means that for type A lithofacies, the differences between different reservoirs are mainly reflected in micropores. The more micropores there are, the higher the proportion of clay intercrystalline pores, and the worse the reservoir type.

[0042] It can be seen that the effective porosity is controlled by both the organic matter content and the clay content.

[0043] Step 3: Analyze the fluid properties of different lithofacies based on 2D NMR oil-bearing interpretation.

[0044] The free oil content of the three main shale phases is slightly different, with the main distribution range being 0.8-4 mg / g. The C phase is slightly worse, which may be due to the more serious loss of light hydrocarbons in the C phase. However, the adsorbed oil content varies greatly. The A phase has the highest adsorbed oil content, followed by the B phase, and the C phase has the lowest adsorbed oil content (average 1 mg / g). Therefore, the total oil content shows A>B>C, and the free oil ratio follows the rule of C>B>A. The average free ratio of the C phase is 69%, while the averages of A and B are mostly less than 50% ( Figure 4 ).

[0045] Step 4: Analysis of controlled factors of oil content.

[0046] The occurrence characteristics of shale oil determine the difficulty of its development. Free oil content and free oil ratio are important parameters for evaluating oil-bearing sweet spots. Studies on interlayer shale oil in the Daqingzijing area show that pore structure (average pore size, effective porosity, etc.) and organic matter abundance are the main factors affecting shale oil occurrence.

[0047] (1) Influence of pore structure on shale oil occurrence

[0048] During the initial migration of crude oil, it will first accumulate in the "sweet spot" area within the source with high porosity and well-developed macropores, and then be discharged from the source rock and migrate to the reservoir. Therefore, a good pore structure is an important factor affecting the occurrence of shale oil. The pore structure of shale is mainly composed of effective porosity, average pore size and pore type.

[0049] 1) Effective porosity

[0050] Shale oil is an in-situ accumulation, so the pore development degree of shale, that is, the size of porosity, determines the shale oil content. Combining the relationship between nuclear magnetic free oil content and effective porosity, it can be found that when distinguishing clay content, nuclear magnetic free oil content is positively correlated with effective porosity, and the free oil content of shale gradually increases with the increase of effective porosity. This is because the oil generated by the source rock will be preferentially stored in its own pores. It will then be expelled from the source rock through episodic hydrocarbon expulsion, and shale oil is the hydrocarbons that remain in the source rock due to poor hydrocarbon expulsion. Therefore, the size of the porosity in the shale determines the enrichment of free oil.

[0051] 2) Average pore size

[0052] The NMR free oil content is positively correlated with the average pore size of the low-temperature nitrogen adsorption experiment, while the adsorbed oil content is weakly negatively correlated with the average pore size. As the average pore size increases, the NMR free oil content gradually increases. At the same time, free oil is mainly present in larger pores with a pore size greater than 40nm, while adsorbed oil is mainly present in pores with a pore size less than 40nm. It can be seen that the points with better shale oil content all have a larger average pore size, and the oil content of shale is controlled by the pore size.

[0053] (2) Impact of organic matter abundance on shale oil occurrence

[0054] Figure 5 The envelope is used to represent the effect of TOC on oil content when other conditions (organic matter type, maturity, reservoir conditions) are at their optimal values. From the envelope in the figure, it can be seen that with the increase of TOC content, the NMR free oil content first increases and then decreases, that is, when the TOC content is less than 2.5%, the NMR free oil content increases with the increase of TOC content; when the TOC content is too high, the NMR free oil content will decrease. This trend is consistent with the effect of TOC on porosity ( Figure 5 Right), that is, TOC has a dual effect on free oil content. This is mainly because pores are the storage space for hydrocarbons. When TOC is less than 2.5%, the effective porosity increases, and the proportion of medium and large pores increases, providing a storage place for free oil; when TOC is greater than 2.5%, the effective porosity decreases, and organic matter fills the pores, so the free oil content decreases.

[0055] It can be seen that the oil content of shale reservoirs is jointly controlled by effective porosity, pore structure and organic matter abundance.

[0056] The above-established method for analyzing the controlled factors of shale reservoir physical properties and oil content is of great significance for clarifying the main controlling factors of shale oil micropores, establishing oil content classification and evaluation standards, and revealing the main controlling factors of shale oil production capacity.

[0057] The above-described embodiments are only preferred embodiments of the present invention, and are not all feasible embodiments of the present invention. For those skilled in the art, any obvious changes made to it without departing from the principles and spirit of the present invention should be considered to be included in the scope of protection of the claims of the present invention. Although the present invention has been described above with reference to the embodiments, various improvements can be made to it and the components thereof can be replaced by equivalents without departing from the scope of the present invention. In particular, as long as there is no technical conflict, the various features in the embodiments disclosed in the present invention can be used in combination with each other in any way, and the fact that these combinations are not exhaustively described in this specification is only for the purpose of omitting space and saving resources. Therefore, the present invention is not limited to the specific embodiments disclosed herein, but includes all technical solutions that fall within the scope of the claims.

Claims

1. A method for analyzing the controlled factors of shale reservoir physical properties and oil content, Its characteristics are: The steps include: Step 1: Determine the reservoir classification standard through one-dimensional nuclear magnetic resonance experiments and mercury injection experiments. Step 2: Analyze the porosity percentage and controlling factors of effective porosity by lithofacies. Step 3: Analyze the fluid properties of different lithofacies based on 2D NMR oil-bearing interpretation. Step 4: Analysis of controlled factors of oil content.

2. A method for analyzing controlled factors of shale reservoir physical properties and oil content as claimed in claim 1, Its characteristic is that the steps In S1, the mercury injection curve of shale samples was fractal studied, and the mercury saturation S Hg and capillary pressure p c There is a relationship between the fractal dimension D and the following: lg(1-S Hg )=(D-3)lgp c -(D-3)lgp cmin Where: S Hg is mercury saturation, %; p cmin It is the capillary pressure corresponding to the maximum pore throat radius, MPa, which is a constant value.

3. A method for analyzing controlled factors of shale reservoir physical properties and oil content as claimed in claim 1, Its characteristics are: In step S2, the movable volume of fluid under certain pressure difference conditions is obtained through the cutoff value of nuclear magnetic resonance logging, or through centrifugation or displacement experiments, which corresponds to the actual movable fluid porosity; the relationship between various porosities and the proportion of medium and large pores is statistically analyzed for different lithofacies.

4. A method for analyzing controlled factors of shale reservoir physical properties and oil content as claimed in claim 2, Its characteristics are: In fractal research, the pore space of shale reservoirs has multiple fractal characteristics, and the fractal inflection point can divide the shale reservoir space into four parts: micropores, small pores, medium pores, and large pores.

5. A method for analyzing controlled factors of shale reservoir physical properties and oil content as claimed in claim 4, Its characteristics are: Micropores are pores with a pore diameter of <30 nm.

6. A method for analyzing controlled factors of shale reservoir physical properties and oil content as claimed in claim 4, Its characteristics are: The small pores are 30-100 nm in size.

7. A method for analyzing controlled factors of shale reservoir physical properties and oil content as claimed in claim 4, Its characteristics are: Mesopores are pores of 100-1000 nm.

8. A method for analyzing controlled factors of shale reservoir physical properties and oil content as claimed in claim 4, Its characteristics are: Macropores are pores >1000 nm.

9. Application of the method for analyzing controlled factors of shale reservoir physical properties and oil content as described in any one of claims 1 to 8 in the Daqingzijing area.

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