A method for evaluating reservoir oil content using complex resistivity response

Abstract

The present invention belongs to the field of geophysical exploration data processing and interpretation technology, and specifically discloses a method for evaluating reservoir oil content by using complex resistivity response, comprising the following steps: S1, establishing a rock complex conductivity model taking into account pore wettability; S2, using observed electromagnetic response to obtain complex conductivity characteristic parameters of the rock formation to achieve quantitative evaluation of reservoir oil saturation. The established relationship model between reservoir oil saturation and complex conductivity parameters can be used to jointly identify the oil content of the reservoir using the resistivity and electrical susceptibility parameters of the reservoir, so as to reduce the multiple solutions of interpretation based solely on resistivity anomalies, and greatly increase the reliability of reservoir fluid identification.

Description

Technical Field

[0001] The invention belongs to the technical field of geophysical exploration data processing and interpretation, and in particular relates to a method for evaluating reservoir oil content by using complex resistivity response. Background Art

[0002] In the exploration stage of oil and gas reservoirs, geophysical exploration technology mainly provides information on the spatial distribution of structures and reservoirs that are conducive to the accumulation of oil and gas. With the improvement of the exploration level, the exploration objects have changed from simple structural oil and gas reservoirs to complex structural oil and gas reservoirs such as high-steep structures, from conventional reservoir oil and gas reservoirs to complex reservoir oil and gas reservoirs such as carbonate fracture-cavity bodies, from structural oil and gas reservoirs to lithologic stratigraphic oil and gas reservoirs, from medium-shallow oil and gas reservoirs to deep-ultra-deep oil and gas reservoirs, and from conventional oil and gas to unconventional oil and gas. This transformation from structural exploration to reservoir evaluation has put forward higher technical requirements for geophysical exploration methods. In order to meet the needs of this transformation, since the 1980s, geophysics for oil and gas exploration has gradually developed and formed three major technical series, including high-resolution imaging, oil and gas reservoir prediction, and fluid property identification, which are mainly based on high-resolution seismic exploration methods and comprehensive application of multi-geophysical information. High-resolution imaging technology is mainly used to accurately depict the geometric morphology of geological bodies; oil and gas reservoir prediction technology aims to depict the spatial distribution and physical properties of oil and gas reservoirs; fluid property identification technology mainly studies the properties and distribution of fluids in reservoirs. On the basis of improving the accuracy of reservoir structure detection, the prediction or evaluation of reservoir oil content can play a decisive role in improving the success rate of oil and gas exploration and reducing exploration costs.

[0003] In terms of oilfield development, a large amount of residual oil is retained underground and difficult to be mined due to the heterogeneity and low quality of the reservoir. To improve the recovery rate, two key issues need to be solved: residual oil detection and tertiary oil recovery technology. To this end, reservoir geophysical technology, which aims at the detailed description of developed reservoirs, dynamic monitoring of injection and production, and residual oil detection, came into being. The development and use of advanced geophysical detection technology to monitor the injection and production dynamics of developed reservoirs, determine the changes in the oil-water interface and the distribution range of residual oil, guide further exploration and development deployment and optimization of development plans, can reduce oilfield production costs, improve recovery rates, and achieve efficient conversion of oil and gas resources.

[0004] At present, artificial source reflection seismic method is the dominant technology in oil and gas geophysical exploration. However, different geophysical methods have different detection performances, including the reflected physical quantities and detection resolution. It is difficult to achieve detailed description of complex reservoirs and fluid identification by relying on a single method. Summary of the invention

[0005] The object of the present invention is to provide a method and system for evaluating reservoir oil content by using complex resistivity response, which can solve the problem that detailed description of complex reservoirs and fluid identification are difficult to achieve.

[0006] The present invention provides a method for evaluating reservoir oil content by using complex resistivity response, comprising the following steps:

[0007] S1, establish a rock complex conductivity model considering pore wettability characteristics;

[0008] S2, using the characteristic parameters of the complex resistivity response of the rock complex conductivity model, quantitatively evaluate the oil saturation of the reservoir.

[0009] Preferably, the S1 specifically includes:

[0010] S11, the rock complex conductivity model considering the pore wettability characteristics is:

[0011]

[0012] Where, σ*—complex conductivity of rock; σ w —pore water conductivity; σ* s —Surface conductivity describing polarization effect; F—formation factor; S w —water saturation; n—saturation index; I w —Wettability index.

[0013] S12, decomposing the saturation index n into a first saturation index and a second saturation index:

[0014] n=q+I w p (2)

[0015] Where q is the first saturation index, which characterizes the influence of the intrinsic pore characteristics of the rock on the rock resistivity, and p is the second saturation index, which characterizes the influence of the fluid properties and distribution characteristics in the rock pores on the rock resistivity.

[0016] S13, the wettability index is introduced to characterize the influence of different wettability tendencies of rock pore surfaces on the polarization effect:

[0017] I w =cos(θ ow ) (3)

[0018] In the formula, θ ow is the contact angle. If the pore surface is completely water-wettable, then θ ow =0°, I w = +1; if the pore surface is completely oil wet, then θ ow =180°, I w =-1.

[0019] Preferably, the saturation index n=2.

[0020] Preferably, the S2 specifically includes:

[0021] S21, in the low frequency band, the complex resistivity phase curve of the reservoir electric polarization effect reflected by the rock complex conductivity model has a peak value, and the characteristic frequency f0 corresponding to the phase peak value is established, and the characteristic phase of the phase value is established. Then the relationship between the corresponding intrinsic relaxation time τ0 and the characteristic frequency f0 is:

[0022]

[0023] S22, the relaxation peak of the phase curve shifts to the low frequency band with the increase of oil saturation, and its quantitative relationship is:

[0024]

[0025] In the formula Characterizes the tortuosity of rock pores, which is the product of formation factor and porosity; D S is the diffusion coefficient of the counterion in the Stern layer, β S is the mobility of the counter ion in the Stern layer; Q is the charge of the ion; d 50 is the average particle size of the rock skeleton particles; k B -Boltzmann constant, T-absolute temperature (K); S w —water saturation; p—second saturation index;

[0026] S23, the relaxation peak of the complex resistivity phase curve changes with oil saturation (S o =1-S w ) shifts to the low frequency band with the increase of , which means that the intrinsic relaxation time τ0 increases with the increase of oil saturation. The oil saturation of the reservoir can be directly and quantitatively explained by the complex resistivity response curve using formula (5);

[0027] The intrinsic relaxation time τ0 of the S24 phase peak is not affected by the wettability tendency of the reservoir pore surface.

[0028] Compared with the prior art, a method for evaluating reservoir oil content by using complex resistivity response according to the present invention comprises the following steps: S1, establishing a rock complex conductivity model taking into account the pore wettability characteristics; S2, using the characteristic parameters of the complex resistivity response of the rock complex conductivity model to quantitatively evaluate the reservoir oil saturation. The established relationship model between the electromagnetic response and the reservoir oil saturation and complex resistivity parameters can be used to jointly identify the reservoir oil content by using the complex resistivity parameters (resistivity and electrical susceptibility) of the reservoir, which can reduce the multiple solutions of the high-resistance anomaly interpretation and greatly increase the reliability of reservoir fluid identification. BRIEF DESCRIPTION OF THE DRAWINGS

[0029] Figure 1 A flow chart of a method for evaluating reservoir oil content by using complex resistivity response provided by the present invention;

[0030] Figure 2 The double electric layer structure of the oil-water interface provided by the present invention;

[0031] Figure 3 Schematic diagram of continuous distribution of oil phase in hydrophilic rock pores provided by the present invention;

[0032] Figure 4 Schematic diagram of discontinuous distribution of oil phase in hydrophilic rock pores provided by the present invention;

[0033] Figure 5 Schematic diagram of continuous distribution of oil phase in pores of oil-wet rocks provided by the present invention;

[0034] Figure 6 The specific surface area (or phase) variation diagram under different oil-water distribution states provided by the present invention;

[0035] Figure 7 The present invention provides laboratory measured resistivity and phase diagram of undercompacted sand particles containing non-wetting oil;

[0036] Figure 8 The present invention provides the resistivity and phase diagram of undercompacted sand particles in the presence of wetting oil measured in the laboratory;

[0037] Fig. 9 The water saturation S provided by the present invention w Relationship diagram with the intrinsic relaxation time τ0. DETAILED DESCRIPTION

[0038] The specific implementation modes of the present invention are described in detail below in conjunction with the accompanying drawings, but it should be understood that the protection scope of the present invention is not limited by the specific implementation modes.

[0039] Unless explicitly stated otherwise, throughout the specification and claims, the term “comprise” or variations such as “include” or “comprising”, etc., will be understood to include the stated elements or components but not to exclude other elements or components.

[0040] like Figure 1As shown, a method for evaluating reservoir oil content by using complex resistivity response according to a preferred embodiment of the present invention includes the following steps: S1, establishing a rock complex conductivity model taking into account the pore wettability characteristics; S2, using the characteristic parameters of the complex resistivity response of the rock complex conductivity model to quantitatively evaluate the reservoir oil saturation. The established relationship model between the electromagnetic response and the reservoir oil saturation and complex resistivity parameters can be used to jointly identify the oil content of the reservoir using the complex resistivity parameters (resistivity and electrical susceptibility) of the reservoir, which can reduce the multiple solutions of the high-resistance anomaly interpretation and greatly increase the reliability of reservoir fluid identification.

[0041] Different types of exploration methods, such as gravity, magnetism, electromagnetic, seismic and logging methods, are complementary to each other. The fluids contained in oil and gas reservoirs are oil, gas and water. Since the water in the reservoir is formation water with a certain degree of mineralization, from the perspective of physical parameters, the density difference between oil and water under reservoir conditions is relatively small (~20%), while the difference in resistivity can reach 5-6 orders of magnitude, and the dielectric constant differs by 40 times. Furthermore, the seismic wave velocity of the oil-bearing reservoir does not change significantly with the oil saturation, while the resistivity value changes dramatically with the oil saturation. Due to the significant difference in resistivity parameters between crude oil and water, the electrical parameters of the reservoir vary greatly when containing different fluids, which can produce obvious electromagnetic anomalies. The electromagnetic response observed on the ground is sensitive to the electrical differences of the detection target. The electrical characteristics of the reservoir when containing different fluids provide a physical basis for the application of controlled source electromagnetic methods to identify reservoir fluids. Based on electromagnetic data, the constrained inversion is comprehensively applied to seismic, logging and other data to improve the accuracy of reservoir electrical structure imaging. The relationship model between electromagnetic response and reservoir oil saturation and complex resistivity parameters established in the study can use the complex resistivity parameters (resistivity and electrical susceptibility) of the reservoir to jointly identify the oil content of the reservoir, reduce the multi-solutions of high-resistance anomalies, and greatly increase the reliability of reservoir fluid identification.

[0042] In a preferred solution, S1 specifically includes:

[0043] S11, the rock complex conductivity model considering the pore wettability characteristics is:

[0044]

[0045] Where, σ*—complex conductivity of rock; σ w —pore water conductivity; σ* s —Surface conductivity describing polarization effects; —water saturation with saturation index n; F —formation factor; —Wettability index is I w The water saturation of the saturation. In the absence of other information, n≈2 can be taken;

[0046] S12, decompose the saturation index n into the first and second saturation indices:

[0047] n=q+I w p (2)

[0048] Where q represents the influence of the intrinsic pore characteristics of the rock on the rock resistivity, and p represents the influence of the fluid properties and distribution characteristics in the rock pores on the rock resistivity;

[0049] S13, the wettability index is introduced to characterize the influence of different wettability tendencies of rock pore surfaces on the polarization effect:

[0050] I w =cos(θ ow ) (3)

[0051] In the formula, θ ow is the contact angle. If the pore surface is completely water-wettable, then θ ow =0°, I w = +1; if the pore surface is completely oil wet, then θ ow =180°, I w =-1.

[0052] In a preferred solution, S2 specifically includes:

[0053] S21, in the low frequency band, the complex resistivity phase curve of the reservoir electric polarization effect reflected by the rock complex conductivity model has a peak value, and the characteristic frequency f0 corresponding to the phase peak value is established, and the characteristic phase of the phase value is established. Then the relationship between the corresponding intrinsic relaxation time τ0 and the characteristic frequency f0 is:

[0054]

[0055] S22, the relaxation peak of the phase curve shifts to the low frequency band with the increase of oil saturation, and its quantitative relationship is:

[0056]

[0057] In the formula Characterizes the tortuosity of rock pores, which is the product of formation factor and porosity; D S is the diffusion coefficient of the counterion in the Stern layer, β S is the mobility of the counter ion in the Stern layer; Q is the charge of the ion; d 50 is the average particle size of the rock skeleton particles; k B -Boltzmann constant (1.38065×10 -23 J / K), T-absolute temperature (K); - water saturation with saturation index p;

[0058] S23, the relaxation peak of the complex resistivity phase curve changes with oil saturation (S o =1-S w ) shifts to the low frequency band with the increase of , which means that the intrinsic relaxation time τ0 increases with the increase of oil saturation. The oil saturation of the reservoir can be directly and quantitatively explained by the complex resistivity response curve using formula (5);

[0059] The intrinsic relaxation time τ0 of the S24 phase peak is not affected by the wettability tendency of the reservoir pore surface.

[0060] Theoretical and experimental studies have shown that when one surface of an object contacts a liquid, charge adsorption and accumulation occur on the contact surface due to physical and chemical reactions, forming two parallel charge layers, called electric double layers (EDL). The object can be a solid particle, bubble, droplet or porous medium. As long as the specific surface area of ​​the interface is large enough, such as colloids or porous media with micron to nanometer-scale particles or pores, there is a significant interfacial EDL effect.

[0061] The electrical properties of rocks are mainly affected by the rock skeleton, pores filled with fluid, and the solid-liquid interface. The EDL effect of the solid-liquid interface is the dominant factor in the low-frequency induced polarization characteristics of rocks. Considering that reservoir rocks are generally sandstone-based, their skeleton components are mainly SiO2, and the skeleton itself is an insulating medium; but their pores are generally filled with groundwater with a certain degree of mineralization, so the resistivity of the solution is very small, so the pore surface of the reservoir rock containing formation water can be regarded as an ideal polarization interface, that is, a double electric layer is formed at the rock skeleton / formation water interface, and its polarity and strength are related to the pH value, ion concentration and migration capacity of the solution.

[0062] The water-bearing reservoir itself has an IP effect due to the double electric layer at the interface between rock particles and fluids. If the reservoir pores contain oil, a relative enhancement of the IP effect (abnormality) may occur. Pure oil and water cannot penetrate each other and are two immiscible liquids. When the oil in the pores comes into contact with water, a clear interface is also formed. Due to the high resistance of oil, it is almost impossible to transfer the charge in the water to the oil phase, so the oil / water interface is also a completely polarizable interface.

[0063] The EDL structure of the oil / water interface is as follows Figure 2As shown, the oil phase 1 and the water phase 2 are two immiscible liquid phases, and their dielectric constants are εo and εw respectively and are constant values. The theoretical contact interface of the oil / water phase is 3, and the compact layer or inner Hehnholtz layer is located between 4 and 5, which is the ion-free space between the surfaces of the ions closest to the interface. The radius of the hydrated inorganic ions (8 and 9) in the aqueous solution is close to 0.1nm, but the organic ions (6 and 7) in the oil phase are usually much larger, with a diameter of about 1nm. The size of such adsorbed organic ions usually exceeds the thickness of the compact layer, and even exceeds the diffusion layer in the concentrated electrolyte solution, so the influence of ion size needs to be considered.

[0064] Oil-bearing reservoirs are porous rock formations, and their pores are composed of effective pores and micropores. In the process of reservoir formation, when oil and gas migrate from the source layer to the reservoir layer, due to the difference in wettability of oil, water and gas to the rock and the effect of capillary force, the migrated oil and gas cannot completely displace the primary water in the rock pores by the pressure difference formed by the gravity difference alone. A certain amount of water will remain in the contact surface, corners and micropores of the rock particles. This part of water that cannot flow in the natural state is called residual water or bound water, and the corresponding evaluation parameter is the bound water saturation S. wi The irreducible water saturation of sandstone reservoirs is related to rock type, porosity and pore structure, among which pore throat diameter and shale content have the most significant influence.

[0065] The wettability of rock particle surface is also an important factor affecting the relative distribution and flow characteristics of oil and water in rock pores. It not only directly restricts the relative permeability of different fluids, but also causes changes in the electrical characteristics of rocks. The wettability of rocks is mainly affected by factors such as the mineral composition of the rock surface, the composition of crude oil, the ion composition and content of formation water or injected water, pH value and temperature.

[0066] In oil reservoirs formed by natural migration, the movable water in the large-diameter (>0.1μm) connected pores of the reservoir within the height range of the oil and gas reservoir is almost completely displaced by oil, forming a continuous oil phase occupying the pores. For hydrophilic rocks, the continuous oil phase does not directly contact the pore wall surface, but is separated by bound water, such as Figure 3 As shown. The bound water 12 between the pore wall surface of the rock skeleton 10 and the continuous oil phase 11 is the result of the interaction of two double electrical layers: the rock solid particle / water interface and the oil / water interface. The double electrical layer at the oil / water interface is generated after the oil is contained. The thickness of the bound water film is equivalent to the sum of the thicknesses of the two double electrical layers, because the layer is mainly composed of adsorbed ions, and the ions or water molecules that can diffuse freely have been replaced. In this way, the pore volume is filled with two continuous but immiscible fluids-oil and water. The relative saturation of water is defined as S w ∈[0;1], then the relative saturation of the oil phase is S o =1-S wFor water-wet rocks, even if they are completely saturated with oil, the oil saturation cannot reach 100%. For example, sandstone with a medium average pore throat radius also has an irreducible water saturation S of about 10%. wi , and the higher the shale content, the smaller the average pore throat radius, S wi The bigger.

[0067] In oil-bearing reservoirs, except for extremely small micropores, oil displaces formation water and occupies the main pores of reservoir rocks. It is obvious that the zero-frequency resistivity of rocks has greatly increased. As for the polarization effect, the double electric layer of the oil / water interface is roughly equivalent to the double electric layer of the original rock skeleton surface / pore water interface, that is, the double electric layer of the corresponding large pore throat wall can be increased by nearly double at most. The enhancement of the polarization effect can be quantitatively evaluated by the increase in specific surface area. Figure 6 Curve 14 in the figure gives the Figure 3 The theoretical calculation results of the increase rate of specific surface area calculated by the oil phase distribution state as the oil saturation changes are shown. The increase rate is defined as the ratio of the specific surface area after oil content to the specific surface area when it is purely saturated with water. It can be seen from the figure that for the continuous oil phase distribution in the hydrophilic rock, the specific surface area increases approximately linearly. In the simple limit case, all the movable water in the rock pores is displaced by oil, and the specific surface area increases to twice the original.

[0068] For oil reservoirs that have entered the development stage, after the reservoir is drilled, due to the elastic energy of the fluid in the rock skeleton and its pores, the difference in the gravity energy of the fluid, the hydrodynamic pressure energy of the edge water and the bottom water, and the expansion energy of the gas at the top of the oil reservoir or the dissolved gas in the oil reservoir, the fluid in the oil and gas reservoir is driven into the well, and the pores where the oil was originally stored are now occupied by reservoir water. This is the reverse process of oil and gas accumulation and migration. Since the viscosity of oil is higher than that of formation water, and the natural energy is generally small, the recovery rate of primary oil recovery using natural energy is generally not high. In order to improve the recovery rate, when natural energy is insufficient or exhausted, artificial energy needs to be supplemented to restore or maintain the formation pressure for production (secondary oil recovery). Common energy supplement methods include top gas injection (gas drive) or edge and middle water injection (water drive). When secondary oil recovery approaches or reaches the economic limit, in order to exploit the remaining oil, various oil recovery media can also be injected from the ground for further production (tertiary oil recovery). The injected oil recovery media include chemical oil recovery agents, solvents, heat carriers, and microorganisms.

[0069] Most of my country's oil fields are continental deposits with complex reservoir types, small sedimentary volumes, and limited natural energy. Therefore, most oil fields were developed by injection and production in the early stages. Regardless of the stage and the type of oil displacement medium used, the ultimate goal is to increase the mobility of oil in rock pores, including maintaining or increasing formation pressure, reducing the viscosity of crude oil, and reducing the adsorption of crude oil by the pore wall. All of these measures will change the original continuous oil phase distribution in the reservoir pores to a discontinuous oil phase distribution, and may also change the wettability of the rock pore walls, such as from a continuous oil-wet surface to a discontinuous oil-wet surface. For example, in water injection production, since the water phase is the wetting phase, the injected water mainly displaces crude oil in the large pores in a non-piston manner, and the oil phase is gradually cut and surrounded by the water phase from a continuous flowable state, gradually forming dispersed and isolated oil droplets and becoming a discontinuous distribution state. Such as Figure 4 As shown in the figure, assuming that these small oil droplets 13 are oil droplets of different particle sizes distributed in the pores, the interface between the outer surface of each oil droplet and the formation water also forms a double electric layer, so that the overall polarization effect of the oil-bearing reservoir will be further enhanced on the original basis. From the perspective of specific surface area, compared with the same volume of continuous oil phase distribution, the specific surface area of ​​discrete oil droplets in water is greatly increased. Figure 6 Curve 15 given in shows an example of the calculation of the increase in specific surface area when the oil phase is discontinuously distributed. The actual increase in specific surface area caused by oil droplets is a complex function of the oil droplet size and the oil-containing volume (or oil saturation), and may be dynamic, changing with time (different development stages) and location (different reservoirs or different oil recovery methods). In general, for the same volume of oil, the smaller the oil droplet size and the greater the number of oil droplets, the greater the increase in specific surface area. In the extreme case, analogous to the experimental analysis results when rich in muddy particles (particle size of several microns), the maximum specific surface area can be increased to about 350 times that of ordinary sandstone.

[0070] Although the surface wettability of reservoir rocks is mainly hydrophilic under original conditions, the reservoir rocks may also become oil-wet due to the influence of factors such as rock particle composition (such as chlorite), asphaltene-rich crude oil or formation temperature, making the hydrophilic surface of the rock pores discontinuous or completely oil-wet. Both oil and rock skeleton are insulating media. If the rock skeleton is oil-wet, the crude oil tightly wraps the surface of the rock skeleton 10, and only a double electric layer with polarization effect is formed between the crude oil 11 and the formation water 12. Consider a simple case, for the continuously distributed oil phase in the completely oil-wet reservoir rock, since part of the original pore space is filled with crude oil, such as Figure 5 As shown in Figure 2, the specific surface area of ​​the oil / water interface that produces the double electrical layer decreases accordingly. In the extreme case, when the oil saturation reaches 100%, the specific surface area approaches zero. Figure 6Curve 16 in the middle gives the theoretical calculation result of the change of rock pore specific surface area with oil saturation under this condition. It can be seen from the figure that when the rock is fully water-containing, the increase rate of the pore specific surface area is 1. As the oil saturation increases, the increase rate of the specific surface area decreases to zero in an approximately linear relationship. The corresponding rock complex resistivity characteristics change with oil saturation in the following way: the zero-frequency resistivity of the reservoir rock increases, the polarization effect weakens, and the relaxation time lengthens. Therefore, the use of polarizability parameters for fluid identification needs to consider the wettability of the rock.

[0071] In most cases, reservoir rocks are hydrophilic. In other words, for the general relationship, the situation when the oil in the reservoir is a non-wetting phase is mainly considered. According to the previous analysis, the rock resistivity satisfies the second Archie law. In other words, for partially water-containing rocks, the formation factor F needs to be replaced by Since the residual charge per unit volume of some water-bearing rocks becomes If the contribution of the surface conductivity is considered to obey the same dependence, it can be written as:

[0072]

[0073] Where, σ*—complex conductivity of rock; σ w —pore water conductivity; σ* s —Surface conductivity describing polarization effects; —water saturation with saturation index n; F —formation factor; —Wettability index is I w The water saturation can be taken as n≈2.

[0074] As mentioned above, the polarization anomaly of an oil-bearing reservoir may increase or decrease with increasing oil saturation, depending on the wettability of the reservoir. The wetting preference of the oil / water interface can be expressed by the adhesion tension, and the magnitude of the surface adhesion tension is determined by the contact angle θ of the droplet at the interface. ow The contact angle is the main measure of wettability. ow =0° indicates a completely water-wet system; and θ ow =180° indicates an oil-wet system; θ ow = 90° represents a neutral wetting system, i.e., two surfaces have the same affinity for the solid surface. w ) to characterize the wettability of rocks:

[0075] I w =cos(θ ow ) (2)

[0076] That is, the cosine of the contact angle. Considering only the cases of complete water wetting and complete oil wetting, for contact angles of 0° and 180°, the corresponding Iw is +1.0 and -1.0, indicating complete water wetting and complete oil wetting, respectively.

[0077] Since the complex resistivity of rock changes inversely with oil saturation when it is oil-wet, based on the relationship shown in formula (1), the saturation index n is decomposed into two components, namely:

[0078] n=q+I w p (3)

[0079] According to formula (1), the relationship between oil saturation and complex conductivity considering wettability is written as:

[0080]

[0081] Note that n at this time is determined according to formula (3).

[0082] In addition to the enhanced EDL effect caused by the increase in specific surface area, the migration of ions in the bound water film under the action of an external electric field will produce a strong film polarization effect. Therefore, compared with fully water-saturated reservoir rocks, the enhanced polarization effect after the reservoir is oil-containing mainly comes from the contributions of the increase in specific surface area and the increase in film polarization effect. At the same time, due to the lack of a free diffusion layer, the polar molecules in the Stern layer are difficult to migrate; and the Stern layer at the oil / water interface is latex-like, and it is more difficult for ions and molecules in the double electric layer to move, which makes it more difficult to establish and restore the polarization field. This is reflected in the complex resistivity parameter that the relaxation time constant increases with the increase in oil saturation, and this change in relaxation time is independent of wettability.

[0083] The complex resistivity phase curve that characterizes the polarization effect changes with frequency and has a peak in the low frequency band. The frequency corresponding to the phase peak is defined as the characteristic frequency f0. As the oil saturation increases, the characteristic frequency shifts to the low frequency end. The relationship between the characteristic frequency f0 and the intrinsic relaxation time τ0 is:

[0084]

[0085] The intrinsic relaxation time is related to the rock particle size, pore characteristics and the diffusion coefficient of ions in the Stern layer of the EDL. For some water-bearing rocks, the relaxation time constant can be written as:

[0086]

[0087] In the formula Characterizes the tortuosity of rock pores, which is the product of formation factor and porosity; D S is the diffusion coefficient of the counterion in the Stern layer, β Sis the mobility of the counter ion in the Stern layer; Q is the charge of the ion; d 50 is the median particle size of the rock skeleton; kB-Boltzmann constant (1.38065×10 -23 J / K), T-absolute temperature (K); S w - water saturation; p-saturation index.

[0088] In a specific implementation scenario:

[0089] The complex resistivity (resistivity amplitude and phase) of undercompacted sand (porosity φ≈0.42) containing oils with different wettability was measured in the laboratory. Figure 7 The resistivity amplitude (Ω) measured with non-wetting oil is shown. m ) and phase (mrad) versus frequency; Figure 8 The curves of resistivity amplitude and phase measured with frequency when containing wetting oil; different curves in the figure correspond to different water saturation (S w ) or oil saturation (S o =1-S w ).

[0090] Non-wetting oil is a non-biodegradable light oil with a mass density of 898 kg / m 3 The wetting oil is taken from the oil field and contains 12% resin and 20% asphalt and other polar components. Its mass density is 850kg / m at 15.6℃. 3 The conductivity of tap water at 20°C used in the measurement of the non-wetting oil phase is σ w =(1.40±0.2)×10 -2 S / m, the conductivity of water at 20°C is σ when used for measuring the wet oil phase w =(0.95±0.2)×10-2S / m.

[0091] Depend on Figure 7 It can be seen that the resistivity and phase of undercompacted sand particles with non-wetting oil measured in the laboratory are as follows:

[0092] Resistivity amplitude curves 19: Sw = 1.0, 20: Sw = 0.8, 21: Sw = 0.6, 22: Sw = 0.4, 23: Sw = 0.2.

[0093] Phase curves 24: Sw=1.0, 25: Sw=0.8, 26: Sw=0.6, 27: Sw=0.4, 28: Sw=0.2.

[0094] Depend on Figure 8 It can be seen that the resistivity and phase of undercompacted sand particles containing wetting oil measured in the laboratory are as follows:

[0095] Resistivity amplitude curves 29: Sw = 1.0, 30: Sw = 0.8, 31: Sw = 0.6, 32: Sw = 0.4, 33: Sw = 0.2.

[0096] Phase curves 34: Sw=1.0, 35: Sw=0.8, 36: Sw=0.6, 37: Sw=0.4, 38: Sw=0.2.

[0097] For both wetting conditions, the phase of the complex resistivity shows obvious relaxation below 1kHz, which is related to the polarization of the EDL. When containing non-wetting oil, the resistivity increases with the increase of oil saturation, obeying the second Archie law; the phase also increases with the increase of oil saturation. For the case of wetting oil, the resistivity and phase are very small and decrease with the increase of oil saturation; the resistivity amplitude is S w = 1.0 when 400Ωm drops to S w = 0.2 for 150Ωm, the phase peak is from full water saturation (S w =1.0) is -3.4mrad lower than that at S w = 0.2 is about -0.5 mrad. It can be seen that the resistivity and phase characteristics of rocks containing oils of different wetting types are completely different, and the resistivity of rocks in the oil-wet condition does not conform to the second Archie law.

[0098] In order to investigate the complex resistivity characteristics of oils with different wettability, Table 1 lists the characteristic frequency f0, characteristic phase and relative frequency of the phase relaxation peak corresponding to non-wetting oil and wetting oil. And the resistivity value corresponding to the relaxation frequency. Note that in the case of oil wetness, the phase peak is not very obvious at low water saturation. If S in Table 1 is used w = 1.0, the characteristic phases of different oil saturations under different wetting conditions are denormalized to obtain the phase increase rate. The phase increase rate calculated from the data in Table 1 is plotted on Figure 6 In the figure, the diamond data point 17 represents the phase increase rate when non-wetting oil is present, and the triangle data point 18 represents the phase increase rate when wetting oil is present. It can be seen from the figure that the phase increase rate when the sand contains non-wetting oil is almost completely coincident with the calculated specific surface area increase rate curve 15 when the oil phase is discontinuously distributed in the pores of hydrowet sandstone; the phase increase rate when wetting oil is present increases with the increase of oil saturation.

[0099] Table 1 Relaxation characteristics of complex resistivity of undercompacted sand particles containing different wettability oils

[0100]

[0101] The decreasing trend is exactly the same as the change trend of the specific surface area increase rate curve 18 calculated when the oil phase is continuously distributed in the pores of oil-wet sandstone, with only a small systematic deviation in the numerical value. This result illustrates the following issues: ① The conclusion that the surface polarization effect of fluid-containing porous rocks is positively correlated with the specific surface area of ​​the pores is correct; ② The dependence of the wettability of the oil contained in the rock on the polarization characteristics obtained by specific surface area analysis is correct; ③ The specific surface area has a decisive influence on the polarization characteristics of fluid-containing porous rocks; ④ When the pores of hydrophilic rocks are partially saturated with oil, the oil may exist in the pores in an incompletely continuous distribution state.

[0102] The water saturation S is plotted after converting the data listed in Table 1 according to the relationship in formula (5). w The relationship with the intrinsic relaxation time τ0 is as follows Fig. 9 The diamond data point 39 in the figure is converted from the data containing non-wetting oil in Table 1, and the triangle data point 40 is converted from the data containing wetting oil in Table 1. It can be seen from the figure that the two sets of data are very consistent, although there may be a large error in the accuracy of determining the peak frequency when containing wetting oil at low water saturation. In the saturation range studied, the fitting curve gives the relationship between τ0 and S w It changes in a negative exponential manner, and p≈1.5.

[0103] In order to verify the validity of the intrinsic relaxation time model given by equation (6), according to the parameters of the materials used in the experiment: F = 3.9, φ = 0.42, d50 = 200 μm for undercompacted sand particles; the mobility of OH- ions in the Stern layer at 25 °C, β s =20.5×10-8m2 / s / V, p≈1.5, then the intrinsic relaxation time at different water saturations calculated by equation (6) is also plotted on Fig. 9 As can be seen from the figure, the relationship between the calculated τ0 and Sw is basically consistent with the measured result. w When ≥0.6, the data points completely overlap. This result shows that the relationship model represented by equation (6) is effective, but for different regions, different rocks and different fluids, it may be necessary to select reasonable parameters based on a variety of information.

[0104] Depend on Figure 7 The measurement results and the parameters of the materials used show that n≈2.14. From the data in Table 1, it can be concluded that the imaginary part of the complex conductivity corresponding to the relaxation peak is 1.72×10 -5 S / m, it can be concluded that the surface conductance of the Stern layer ΣS=1.72×10 -9 S, and the theoretical value is 2.0×10 -9 S is similar. The relationship curve between different water saturations and the imaginary part of complex conductivity is fitted to obtain the saturation index of the imaginary part: That is, n-1≈1.26, which is close to n=2.14 obtained by fitting the real conductivity. This explains two problems: ① and σ w In comparison, it is reasonable to ignore the contribution of surface conductivity to the real part of rock conductivity; ② The relationship model between the complex resistivity of hydrophilic rocks and oil saturation represented by formula (1) (formula (3)) is effective and can be used to interpret measured data under the same conditions.

[0105] By fitting Figure 7 and Figure 8 The real and imaginary parts of the measured data are shown in Figure 1, and we get q≈0.67 and p≈1.45. Thus, for the completely water-wet condition, we have w = +1, n≈2.12, nI w ≈1.12; the corresponding fitting value is n≈2.12, nI w ≈1.26. In the case of complete oil wetness, I w =-1, n≈-0.78, nI w ≈0.22; the corresponding fitting value is n≈-0.77, nI w ≈0.4. Considering that in the case of oil wetness, the value of the imaginary conductivity itself is very small and is greatly affected by the measurement accuracy, so overall, the fitting results of the model can verify the effectiveness of the quantitative evaluation model (Formula (4)).

[0106] The foregoing description of specific exemplary embodiments of the present invention is for the purpose of illustration and demonstration. These descriptions are not intended to limit the present invention to the precise form disclosed, and it is clear that many changes and variations can be made based on the above description. The purpose of selecting and describing the exemplary embodiments is to explain the specific principles of the present invention and its practical application, so that those skilled in the art can realize and utilize various different exemplary embodiments of the present invention and various different selections and changes. The scope of the present invention is intended to be limited by the claims and their equivalents.

Claims

1. A method for evaluating reservoir oil content using complex resistivity response, characterized in that: The following steps are involved: S1, establish a rock complex conductivity model considering pore wettability characteristics; The S1 specifically includes: S11, the rock complex conductivity model considering the pore wettability characteristics is: Where, σ*(ω)—complex conductivity of rock; σ w —pore water conductivity; σ* s —Surface conductivity describing polarization effect; F—formation factor; S w —water saturation; n—saturation index; I w —Wettability index; S12, decomposing the saturation index n into a first saturation index and a second saturation index: n=q+I w p (2) Where q is the first saturation index, which characterizes the influence of the intrinsic pore characteristics of the rock on the rock resistivity, and p is the second saturation index, which characterizes the influence of the fluid properties and distribution characteristics in the rock pores on the rock resistivity. S13, the wettability index is introduced to characterize the influence of different wettability tendencies of rock pore surfaces on the polarization effect: I w =cos(θ ow ) (3) In the formula, θ ow is the contact angle. If the pore surface is completely water-wettable, then θ ow =0°, I w = +1; if the pore surface is completely oil wet, then θ ow =180°, I w = -1; S2, using the observed electromagnetic response to obtain the complex conductivity characteristic parameters of the rock formation, to achieve quantitative evaluation of the oil saturation of the reservoir.

2. The method for evaluating reservoir oil content by using complex resistivity response according to claim 1, characterized in that: S21, in the low frequency band, the complex resistivity phase curve of the reservoir electric polarization effect reflected by the rock complex conductivity model has a peak value, and the characteristic frequency f0 corresponding to the phase peak value is established, and the characteristic phase of the phase value is established. Then the relationship between the corresponding intrinsic relaxation time τ0 and the characteristic frequency f0 is: S22, the relaxation peak of the phase curve shifts to the low frequency band with the increase of oil saturation, and its quantitative relationship is: In the formula Characterizes the tortuosity of rock pores, which is the product of formation factor and porosity; D S is the diffusion coefficient of the counterion in the Stern layer, β S is the mobility of the counter ion in the Stern layer; Q is the charge of the ion; d 50 is the average particle size of the rock skeleton particles; k B -Boltzmann constant, T-absolute temperature (K); S w - water saturation; p- second saturation index; S23, the relaxation peak of the complex resistivity phase curve changes with the oil saturation S o The increase of S shifts to the low frequency band, which means that the intrinsic relaxation time τ0 increases with the increase of oil saturation. The oil saturation of the reservoir can be directly and quantitatively explained by the complex resistivity response curve using formula (5); o =1-S w ; The intrinsic relaxation time τ0 of the S24 phase peak is not affected by the wettability tendency of the reservoir pore surface.

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