CN111537541A - Compact reservoir CO2Method for evaluating driving characteristics of reservoir - Google Patents
Compact reservoir CO2Method for evaluating driving characteristics of reservoir Download PDFInfo
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Abstract
The invention discloses a compact oil reservoir CO2The method for evaluating the driving reservoir exploitation characteristics comprises the steps of classifying and evaluating the micro-pore structure of a compact reservoir according to a reservoir classification standard, and classifying the micro-pore structure into a first class, a second class and a third class; then sampling at least one core from the first type, the second type and the third type respectively, and carrying out saturated simulation on formation water on three different types of cores; continuing to saturate the original dehydrated and degassed crude oil to the rock core saturated with the simulated formation water; then, a tubule experiment is carried out to determine CO2Minimum miscible pressure with crude oil; finally, performing a carbon dioxide flooding experiment, and performing nuclear magnetic resonance T on rock cores under different experimental pressures2Spectrum sampling is carried out, corresponding oil displacement efficiency is calculated, and CO is realized under different pressures of a compact reservoir2The mobility characteristics of large and small pores in the oil displacement process are evaluated, and CO is reasonably and efficiently developed for compact oil reservoirs2The method and the basis are provided.
Description
Technical Field
The invention belongs to the technical field of compact oil reservoirs, and particularly relates to compact oil reservoir CO2A driving reservoir characteristic evaluation method.
Background
In recent years, with the gradual decrease of conventional oil and gas resources, the exploration and development of unconventional energy sources, particularly compact oil and gas, are increased worldwide.
The reservoir of the tight oil reservoir is subjected to uneven diagenetic and compaction in the deposition process, so that the target reservoir rock is formedThe stone is dense and has strong heterogeneity, the porosity is 1.15-15.54%, and the permeability is 0.03-4.5 × 10-3μm2. The complex pore structure characteristics result in poor water injection development effect and serious ineffective water circulation. Research on the technology of improving the recovery ratio of tertiary oil recovery needs to be developed on the basis of recognization of a reservoir, so as to solve the current dilemma.
CO2Flooding has become more and more widely used as the primary technique for enhancing oil recovery three times. CO injection under high-temperature and high-pressure conditions in oil reservoir2The gas is in a supercritical state, the unique phase state characteristics of the gas can be mutually dissolved with the crude oil and have mass transfer effect, the viscosity and the interfacial tension of the crude oil are reduced, meanwhile, the gas can enter micro pores which cannot be reached by a water phase, the displacement efficiency is improved, and the water flooding area is enlarged. However, because the core is in a closed black box environment, it is difficult to directly observe and measure the characteristics of crude oil movement and the distribution characteristics of residual oil in different pores. At present, scholars at home and abroad mainly adopt a core thin slice microscopic model, an online CT scanning technology, nuclear magnetic resonance and other modes to research the fluid seepage characteristic and the residual oil distribution characteristic in the core. The core slice microscopic model belongs to one-dimensional simulation, and quantitative characterization of residual oil is difficult to carry out. Although on-line CT scanning can provide an intuitive residual oil distribution image, the accuracy of the scanning result has a great relationship with image processing and resolution, the subjective influence is serious, and quantitative analysis on the change of oil phase in pore throats with different apertures cannot be carried out.
Disclosure of Invention
In order to solve the problems, the invention provides a compact reservoir CO2A reservoir driving characteristic evaluation method is used for reasonably and efficiently developing CO for a tight oil reservoir by researching rock cores with different pore structure types2The method and the basis are provided.
The technical scheme adopted by the invention is as follows:
compact oil reservoir CO2The evaluation method of the characteristic for driving the reservoir is implemented according to the following steps:
s1, classifying the micro-pore structures of the compact oil reservoir, and classifying the micro-pore structures into a first class, a second class and a third class according to the reservoir classification standard;
s2, sampling at least one core from the first type, the second type and the third type in the S1 respectively, and performing saturated simulation formation water on the cores with three different pore structure types;
s3, continuing to saturate the original dehydrated and degassed crude oil to the core saturated with the simulated formation water;
s4, performing a tubule experiment to determine CO2Minimum miscible pressure with crude oil;
s5, performing a carbon dioxide flooding experiment, and performing nuclear magnetic resonance T on rock cores under different experimental pressures2Spectrum sampling is carried out, corresponding oil displacement efficiency is calculated, and CO is realized under different pressures of a compact reservoir2Evaluating the dynamic characteristics of large pores and small pores in the oil displacement process.
Preferably, in S5, a carbon dioxide flooding experiment is performed, and nuclear magnetic resonance T is performed on the cores at different experimental pressures2Spectrum sampling, specifically:
s51, raising the experimental pressure to the corresponding gas injection pressure through the intermediate container pressure holding;
s52, injecting carbon dioxide into the core from the inlet end of the core under the different gas injection pressures of the S51 until the outlet end of the core produces no oil;
in S52, the carbon dioxide injection amount and the oil production amount were recorded, and the core after the experiment was sampled by a T2 spectrum.
Preferably, the reservoir classification criteria in S1 are:
and classifying according to the porosity, permeability, movable fluid saturation, movable fluid porosity, displacement pressure, median pressure, sorting coefficient, pore throat radius, maximum pump inlet saturation and pore throat combination parameters of the rock core.
Preferably, in S2, the saturated formation water simulation is performed on cores of three different pore structure types, specifically:
firstly, cleaning and drying a rock core, then putting the rock core into a holder, vacuumizing the rock core for 12 hours after confining pressure of 2-3 MPa is added, and then fully saturating the simulated formationWater, and subjecting the core in this state to T2And (4) spectrum sampling.
Preferably, in S3, the core saturated with the simulated formation water is continuously saturated with the original dehydrated and degassed crude oil, specifically:
injecting dehydrated and degassed crude oil into the core at the temperature of 60 ℃ at the speed of 0.01mL/min to displace formation water in the core until no water is discharged from an outlet end; and when the oil phase permeability error is measured for 3 times continuously and is less than 5%, stopping injecting the degassed crude oil, and performing T on the core in the state2And (4) spectrum sampling.
Preferably, the different gas injection pressures in S51 include: 6MPa, 12MPa, 18MPa and 22 MPa.
Preferably, the S52 further includes:
and when the outlet end of the core does not produce oil, continuously injecting 2PV carbon dioxide.
Compared with the prior art, the method has the advantages that the pore structure of the rock core of the compact oil reservoir is judged, and the rock core is divided into a first type, a second type and a third type according to the reservoir classification standard; then sampling at least one core from the first type, the second type and the third type respectively, and then performing saturated simulation of formation water on three different types of cores; then injecting degassed crude oil into the rock core after the saturated simulation of the formation water to displace the formation water in the rock core; then, performing a tubule experiment to determine the minimum miscible pressure; and finally, injecting carbon dioxide into the rock core, sampling the rock core in the state to obtain the oil displacement efficiency, realizing the evaluation of the reservoir exploitation characteristics, and developing CO for the compact reservoir reasonably and efficiently2The method and the basis are provided.
Drawings
FIG. 1 is a compact reservoir CO provided by the embodiment of the invention2A flow chart of a driving reservoir exploitation feature evaluation method;
FIG. 2 is a compact reservoir CO provided by the embodiment of the invention2The oil displacement efficiency of the typical rock samples of the three types of reservoirs in the reservoir driving characteristic evaluation method changes along with the displacement pressure;
FIG. 3 is a first type of reservoir 20# rock sample displaced to residual oil at different displacement pressuresT in state2A spectrum;
FIG. 4 is a graph of the displacement efficiency of a first type of reservoir No. 20 rock sample in large and small pores at different displacement pressures;
FIG. 5 is T of second type reservoir No. 1 rock sample at different displacement pressures displaced to a residual oil state2A spectrum;
FIG. 6 is the displacement efficiency of a second type I reservoir type 1 rock sample in large and small pores at different displacement pressures;
FIG. 7 is T of a third type of reservoir 36# rock sample at different displacement pressures displaced to a residual oil state2A spectrum;
FIG. 8 is the displacement efficiency of a third type of reservoir 36# rock sample in large and small pores at different displacement pressures;
FIG. 9 is a comparison of displacement efficiency in small pores for three types of reservoirs at different displacement pressures;
fig. 10 is a comparison of the displacement efficiency in large pores for three types of reservoirs at different displacement pressures.
Detailed Description
In order to make the objects, technical solutions and advantages of the present invention more apparent, the present invention is further described in detail with reference to the following embodiments. It should be understood that the specific embodiments described herein are merely illustrative of the invention and are not intended to limit the invention.
The embodiment of the invention provides a compact oil reservoir CO2The method for evaluating the driving characteristics of the reservoir is implemented according to the following steps as shown in figure 1:
s1, classifying the micro-pore structures of the compact oil reservoir, and classifying the micro-pore structures into a first class, a second class and a third class according to the reservoir classification standard;
s2, sampling at least one core from the first type, the second type and the third type in the S1 respectively, and performing saturated simulation formation water on the cores with three different pore structure types;
s3, continuing to saturate the original dehydrated and degassed crude oil to the core saturated with the simulated formation water;
s4, performing a tubule experiment to determine CO2Minimum miscible pressure with crude oil;
s5, performing a carbon dioxide flooding experiment, and performing nuclear magnetic resonance T on rock cores under different experimental pressures2Spectrum sampling is carried out, corresponding oil displacement efficiency is calculated, and CO is realized under different pressures of a compact reservoir2Evaluating the dynamic characteristics of large pores and small pores in the oil displacement process.
Specifically, in S1, classification is performed according to the porosity, permeability, mobile fluid saturation, mobile fluid porosity, displacement pressure, median pressure, sorting coefficient, pore throat radius, maximum intake pump saturation, pore throat combination, and void type of the core;
in table 1, 11 parameters of porosity, permeability, mobile fluid saturation, mobile fluid porosity, displacement pressure, median pressure, sorting coefficient, pore throat radius, maximum mercury inlet saturation, pore throat combination and pore type are selected as characteristic parameters for reservoir evaluation by performing scanning electron microscope, high-pressure mercury intrusion, cast body slice and nuclear magnetic resonance T2 spectrum analysis on 43 rock core samples, and three types of reservoir classification evaluation standards are established.
TABLE 1
The first type of reservoir is the reservoir with the best physical property and pore structure, but the reservoir accounts for a lower percentage of 18.6% (8 of 43 samples belong to the reservoir), the porosity of the reservoir is 8-11.7%, the permeability is 0.11-1.2 × 10-3 mu m2, and the reservoir has the T-shaped nuclear magnetic resonance2Spectrally known, reservoir T of the first type2The spectrum form is mainly double peaks which are clearly separated and basically symmetrical; the mobile fluid saturation is above 62.5%, and the average mobile fluid porosity is 6.2%; the average displacement pressure is 0.75MPa, the separation coefficient is 1.9-3.7, the average value of pore throat radius is 0.55 mu m, and the mercury feeding saturation can reach 87.95% on average; the pore type mainly comprises original pores, erosion pores and microcracks among grains, and the throat type mainly comprises a pore-reduced throat.
Taking a representative sample in the first reservoir as an example, the displacement pressure is 0.68MPa, and the maximum displacement pressure isThe mercury-in saturation is 86.78%; t is2The area enveloped by the relaxation time corresponding to the left peak in the spectrum distribution is basically equal to the area enveloped by the relaxation time of the right peak, the microcrack is relatively developed, the saturation of the movable fluid is 68.5 percent, and the porosity of the movable fluid is 7.6 percent.
The second type of reservoir deviated from the first type of reservoir, but the second type of reservoir accounted for a higher percentage, up to 46.5% (20 of the 43 samples belong to this type), the second type of reservoir had an average porosity of 8.8% and an average permeability of 0.14 × 10-3μm2；T2The spectrum form is mainly a double-peak form with a left peak higher than a right peak, the saturation of the movable fluid is 41.4-62.5%, and the porosity of the movable fluid is 2.2-4.3%; the drainage and displacement pressure is higher than the average value of the first reservoir and is 1.43MPa, the sorting coefficient is 0.1-2.6, the average pore throat radius is 0.37 mu m, and the maximum average mercury-feeding saturation is 85.41%; most of the pore types are rock debris dissolving pores and inter-granular pores, and the throat types are mainly necking throats and bent sheet throats.
Taking a representative sample in the second reservoir as an example, the displacement pressure is 0.89MPa, and the maximum mercury-entering saturation is 84.84%; t is2The left peak is higher than the right peak in the spectral distribution, the right peak is relatively weak in development, the saturation of the movable fluid is 57.3%, and the porosity of the movable fluid is 3.9%.
The third type of reservoir was the worst but with a percentage of up to 35% (15 out of 43 samples belong to this type), an average porosity of 7.7%, and an average permeability of 0.08 × 10-3μm2(ii) a Compared with the former two reservoirs, the third reservoir has the average mobile fluid saturation of only 28.6%, the mobile fluid porosity of 1.2%, and the T2The spectrum form is mainly a single-peak form with obvious bound fluid peaks, and the small pore throat content of the reservoir is high, the connectivity is poor and the bound fluid content is high. The average displacement pressure is up to 3.75MPa, the sorting coefficient is between 0.1 and 2.2, the average pore throat radius is 0.15 mu m, and the maximum average mercury inlet saturation is 68.32 percent; the pore type is mainly micropore and intercrystalline pore, and the throat type is mainly tube-bundle throat.
Taking a representative sample in the third reservoir as an example, the displacement pressure is 3.57MPa, and the maximum mercury-feeding saturation degree is 67.26%.T2The spectrum distribution is unimodal, the proportion of dead pores and blocked throats in large and medium pores is high, the connectivity is poor, the saturation of the movable fluid is only 9.7 percent, and the porosity of the movable fluid is 1.2 percent.
In the S2, at least one core is sampled from the first type, the second type and the third type in the S1 respectively, then the core is cleaned and dried, then the core is placed in a holder, the core is vacuumized for 12 hours after the confining pressure is increased by 2-3 MPa, then the simulated formation water is fully saturated, and the T is carried out on the core in the state2Spectrum sampling;
in particular, T2The spectrum sampling adopts a nuclear magnetic resonance technology, which is to measure the amplitude and relaxation rate of a nuclear magnetic resonance relaxation signal of hydrogen nuclei in rock pore fluid by utilizing the self magnetism of the hydrogen nuclei and the principle of the interaction of the hydrogen nuclei and an external magnetic field and establish T by carrying out mathematical inversion on the acquired signal2Relaxation time spectrum to research the pore structure of rock. Nuclear magnetic resonance T2The abscissa of the spectrum represents the relaxation time and the ordinate represents the fraction of the different relaxation time components. According to T2Expression of relaxation time
(where ρ is the rock surface relaxation constant, F)sIs a pore shape factor, related to the rock pore radius r), T is known2The value is in direct proportion to the radius of the rock pore throat, namely the relaxation time corresponding to large pores in the rock core is long, and the relaxation time corresponding to small pores is short. Nuclear magnetic resonance T2The spectra can directly reflect the distribution of fluids in different size pores in the core. According to the results of the early nuclear magnetic resonance experiments, the optimum centrifugal force for the calibration of 43 rock samples of the reservoir with the length of 8 reservoir zones in the research region is 1.85MPa and T2The cutoff value is 4.78 ms. Due to nuclear magnetic resonance T2Both the spectrum and the mercury intrusion curve can be used for characterizing the distribution of the internal pore structure of the rock, the radius of pore throat and the relaxation time T2The positive correlation between the two can be mutually converted, and T can be known by calculation2The cutoff value corresponds to a minimum mobile fluid pore throat radius of 0.187 μm. Therefore, T is defined in this application2The value is in the range of 0.01 to 5msInner, i.e. the pore throat with the pore throat radius less than 0.187 μm is a small pore throat; t is2The value is in the range of 5 to 1000ms, i.e., the pore throat with a pore throat radius of more than 0.187 μm is the large pore throat.
S3, continuing to saturate the original dehydrated and degassed crude oil to the core saturated with the simulated formation water; the method specifically comprises the following steps: injecting degassed crude oil into the core at a speed of 0.01mL/min at a temperature of 60 ℃ to displace formation water in the core until no water is discharged from an outlet end; and when the oil phase permeability error is measured for 3 times continuously and is less than 5%, stopping injecting the degassed crude oil, and performing T on the core in the state2Spectrum sampling;
s4, performing a tubule experiment, and determining the minimum miscible pressure of the CO2 and the crude oil;
s5, performing a carbon dioxide flooding experiment, and performing nuclear magnetic resonance T on rock cores under different experimental pressures2Spectrum sampling is carried out, corresponding oil displacement efficiency is calculated, and CO is realized under different pressures of a compact reservoir2The evaluation of the dynamic characteristics of large and small pores in the oil displacement process specifically comprises the following steps:
s51, raising the experimental pressure to the corresponding gas injection pressure through the intermediate container pressure holding; the corresponding insufflation pressures include: 6MPa, 12MPa, 18MPa and 22 MPa;
s52, injecting carbon dioxide into the core from the inlet end of the core at an injection speed of 0.1mL/min under different gas injection pressures of the S51 until the outlet end of the core produces no oil;
s53, when the oil is not produced at the outlet end of the rock core, continuously injecting 2PV carbon dioxide;
in S52 and S53, carbon dioxide injection and oil production were recorded, and the cores after the experiment were sampled for a T2 spectrum.
The rock cores used in the specific process are 4 typical rock samples of three different types of reservoirs respectively, and specific basic parameters are shown in table 2; the experimental oil was a formation degassed crude oil (density 0.78 × 103kg/m3, viscosity 12.43mPa · s under surface conditions) and jet fuel oil at a volume of 1.5: 1, the density of the compounded simulated oil is 0.74 multiplied by 103kg/m3, and the viscosity is 6.82 mPa.s.
TABLE 2
Through the thin tube experiment in S4, the simulated oil and CO can be obtained2The Minimum Miscible Pressure (MMP) of 17.4MPa (experimental temperature 60 ℃ formation temperature). The experimental water is simulated formation water with equal mineralization degree prepared according to the analysis data of the actual formation water, the mineralization degree is 3640mg/L, and the viscosity is 0.98 mPa. Meanwhile, 1.5 percent of manganese chloride solution is added into simulated formation water, so that the formation water does not generate nuclear magnetic resonance signals. CO for the experiments2The purity of the gas was 99.9%. The experimental temperature was 60 ℃ formation temperature.
By comparing the oil displacement efficiency of the three types of reservoir cores (taking the average value of the oil displacement efficiency of 4 lower core cores of each type of reservoir) (figure 2), the oil displacement efficiency of the three types of reservoir cores is along with the CO2The injection pressure increases. When the displacement pressure is lower than MMP (17.4MPa), the oil displacement efficiency of the third reservoir is the largest, and the oil displacement efficiency of the first reservoir is the lowest in the second reservoir. When the displacement pressure is increased to 22MPa (greater than MMP), the potential of the second reservoir is excited, and the maximum displacement efficiency is 66.1%; next to the third reservoir, the first reservoir was the smallest, only 53.5%.
In summary, the third reservoir is suitable for developing CO2Non-miscible flooding, the second reservoir is suitable for developing CO2And (4) miscible phase driving.
According to the nuclear magnetic resonance T when the first type reservoir typical rock sample (20#) is displaced to a residual oil state under different displacement pressures2The spectra (FIG. 3) show that when the displacement pressure is lower than MMP, CO is injected2Only the oil phase with relaxation time of 5-1000 ms in large pores and the T of small pores in the range of 0.01-5 ms for activation2The amplitude variation is small. T of large and small pores when displacement pressure is raised to MMP2The amplitude values are obviously reduced, which shows that the crude oil existing in small pores is gradually used under the miscible pressure, and the oil displacement efficiency is continuously increased.
According to the figure 3, the oil displacement efficiency of big and small pores under different displacement pressures (figure 4) can be calculated, and under the displacement pressure of 6MPa, CO is adopted2The oil displacement efficiency of the macropores is 8.4 percent, while the oil displacement efficiency of the micropores is only 0.9 percent. CO injection when the pressure rises to 12MPa2The large pores with smaller entry resistance are still preferentially selected, so that the oil displacement efficiency in the large pores is further increased (18.3 percent), and the oil displacement efficiency in the small pores is increased by only 1.4 percent. When the pressure is increased to 18MPa, the oil displacement efficiency of the large pore and the small pore is greatly improved, and the oil displacement efficiency of the small pore is increased to 26.2 percent, because CO is used after the displacement pressure reaches the minimum miscible pressure2The extraction and evaporation capacity of the crude oil is enhanced, the interfacial tension between the crude oil and the crude oil is eliminated, and CO is generated2The oil can smoothly enter small pores with originally larger resistance, and crude oil is displaced in a piston mode, so that the oil displacement efficiency is greatly improved. When the pressure is increased to 22MPa, the oil displacement efficiency in the large pores is 65.3 percent and is 53.8 percent higher than that in the small pores, which is mainly caused by CO2Miscible with crude oil is a process of multiple contact, even at pressures above the miscible pressure, with CO2But will still preferentially enter the macropores where they are the main flow channels and diffuse towards the surrounding small pore throats to form miscible displacement.
Nuclear magnetic resonance T of a second type reservoir typical rock sample (1#) in the residual oil state under different displacement pressures2The spectrum (figure 5) shows that, unlike the first reservoir type, the T2 amplitude value of the small pores of the second reservoir type is obviously reduced under the unmiscible pressure, which indicates that the small pores are in CO2Crude oil found in the small pores of the second reservoir during immiscible flooding can also be mobilized. In addition, under immiscible pressure, T2T of pores having a relaxation time of 3 to 8ms (reduced pore throat radius of 0.122 to 0.415 μm)2The amplitude value is not decreased or increased, which indicates that the occurrence state of the crude oil is changed in the displacement process, and the crude oil expelled from certain macropores enters the pores with the pore throat radius and cannot be expelled again. T of large and small pores when displacement pressure reaches MMP2The amplitude values are all greatly reducedIndicating a substantial reduction in crude oil present in the pores.
As can be seen from fig. 6, when the displacement pressure is lower than MMP, the displacement efficiency increase amplitudes of the large pores and the small pores are basically consistent with each other along with the increase of the displacement pressure, but the oil displacement efficiency of the small pores is slightly lower than that of the large pores. In the second reservoir, the pore throat type is mainly a small pore-thin throat type, the proportion of large pores is relatively small, the communication characteristics among the large pores and the small pores are relatively complex, and the capillary pressure distribution is uneven, so that after CO2 enters the large pores, the pressure in the pores flows to the small pore throats with uneven capillary force distribution on the periphery after reaching a certain degree, and the crude oil in the small pores can be used to a certain degree without channeling along the large pores like the first reservoir. When the displacement pressure is increased to 18MPa, the oil displacement efficiency of the large pore and the small pore is obviously increased, and the increase range of the oil displacement efficiency of the small pore is higher than that of the oil displacement efficiency of the large pore, which shows that the utilization capacity of the existing crude oil in the small pore is obviously enhanced after the CO2 reaches the miscible pressure. When the pressure is continuously increased to 22MPa, the oil displacement efficiency of large pores can reach 81.9%, and the oil displacement efficiency of small pores can also reach 69.8%. It is demonstrated that whether in CO2 miscible or immiscible flooding, the large pores are the main flow channels of CO2, and the oil displacement efficiency is always higher than that of the small pores.
According to a nuclear magnetic resonance T2 spectrum (shown in figure 7) of a third type reservoir typical rock sample (36#) in a residual oil state under different displacement pressures, the large pore ratio of the 36 rock sample is very low, more than 90% of pore throats of the 36 rock sample belong to small pore throats within the range of 0.01-5 ms, and the connectivity between the large pore and the small pore is very poor according to the T2 spectrum in a saturated formation water state. Thus, when the displacement pressure was increased to 12MPa (below MMP), there was a large drop in the large pore T2 amplitude; when the displacement pressure is increased to 18MPa, the crude oil existing in the macropores is basically completely displaced.
Combining the oil displacement efficiency of large and small pores in the rock core (figure 8), the oil displacement efficiency of the small pores is 21.1% under the displacement pressure of 12MPa, which is far higher than the movable fluid saturation measured after centrifugation by 9.7%, and the CO under the supercritical state is shown2Can be used forEntering a fine pore throat where the water phase cannot enter to displace the crude oil. At the same time, the small pore occupancy ratio results in CO2The crude oil "has to" be displaced into small pores with a resistance smaller than the displacement pressure. When the pressure rises to 18MPa, CO2The oil can enter a finer pore throat under high pressure, and the crude oil in the finer pore throat is displaced in a piston mode after being mixed with the crude oil, so that the oil displacement efficiency of small pores is increased to 49.2 percent. When the pressure is increased to 22MPa, CO2The oil displacement efficiency of the small pores can reach 61.8 percent finally. The oil displacement efficiency can reach 99.7% due to the small amount of the original oil and the low proportion of the original oil in the macropores.
By comparing the oil displacement efficiency of the small pores of the three types of reservoirs under different displacement pressures (fig. 9), when the displacement pressure is lower than the miscible phase pressure, the oil displacement efficiency of the small pores of the third type of reservoir is the largest, and the oil displacement efficiency of the small pores of the second type of reservoir is the lowest, namely the first type of reservoir. When the displacement pressure is higher than MMP, the oil displacement efficiency of the small pores of the second reservoir is increased to the maximum, and the first reservoir is the lowest in the third reservoir. This is due to CO2In the process of immiscible driving, CO2Entering into macropores from the middle part of pore throat as strong non-wetting phase, accumulating and expanding in the macropores, extruding and displacing crude oil to the periphery of the pore, and when the pressure in the macropores reaches the pressure of capillary tube capable of overcoming the periphery communicated with the pore throat, CO2It will pass down into the next throat. Therefore, in three types of reservoirs with poor reservoir physical properties, complex pore throat characteristics and low large pore occupation ratio, CO2The easier it is to get into the fine pore throat; the first type of reservoir with good reservoir physical property and high macropore occupation ratio is easy to generate gas channeling, so that the small pores cannot be filled with CO2And (4) carrying out the sweep. When the displacement pressure reaches MMP, due to CO2Mixing is a multiple contact process, CO2Firstly, the crude oil enters the macropores preferentially, and then is mixed with the crude oil gradually in the macropores or the micropores, or enters the micropores in a mixed phase mode after being mixed in the macropores. T of reservoir type II2The spectrum is bimodal, but the left peak is higher than the right peak, which shows the type of storageSmall pores of the layer (thin) are developed, meanwhile, partial large pores are developed, and the connectivity of the large pores and the small pores is better than that of the third reservoir, so that the CO is ensured2And the oil can enter the small pores again after entering the large pores, so that the oil displacement efficiency in the small pores of the second reservoir is highest.
By comparing the oil displacement efficiency of macroporosity under different displacement pressures (fig. 10), the oil displacement efficiency of the macroporosity of the third reservoir is highest, the oil displacement efficiency of the second reservoir is second, and the oil displacement efficiency of the first reservoir is lowest. This is because the large pore ratio decreases and the connectivity deteriorates as the pore structure of the reservoir deteriorates, resulting in a decrease in the amount of crude oil in the large pores. Meanwhile, according to the results of the above experiments, it can be seen that CO is not contained in the mixed phase or the non-mixed phase2First, the carbon dioxide enters large pores with low resistance, so that CO is generated2And crude oil in large pores of the third type reservoir can be more easily driven out.
Through the analysis of the embodiment, the storage performance and the seepage capability corresponding to the three types of reservoirs are sequentially reduced, and the physical properties and the pore structures of the reservoirs are sequentially deteriorated, wherein the second type of reservoir has the highest ratio in 43 rock cores of the sample and is the key direction of subsequent exploration and development; in CO2In non-miscible flooding, the oil displacement efficiency of the third reservoir is the maximum, the second reservoir is the lowest, the first reservoir is the lowest, and CO is the highest2Primarily displacing crude oil present in the macropores; in CO2In miscible flooding, the second reservoir has the highest oil displacement efficiency, the third reservoir has the lowest oil displacement efficiency, the first reservoir has the lowest CO2Preferentially enter the macropores while displacing the crude oil present in the large and small pores. CO in the actual mine2In the injection process, a gas-water alternative injection mode is suggested to be adopted so as to improve the oil displacement efficiency and the swept area of the second reservoir and the third reservoir.
The above description is only for the preferred embodiment of the present invention, but the scope of the present invention is not limited thereto, and any changes or substitutions that can be easily conceived by those skilled in the art within the technical scope of the present invention are included in the scope of the present invention. Therefore, the protection scope of the present invention shall be subject to the protection scope of the claims.
Claims (8)
1. Compact oil reservoir CO2The method for evaluating the driving characteristics of the reservoir is characterized by comprising the following steps of:
s1, classifying the micro-pore structures of the compact oil reservoir, and classifying the micro-pore structures into a first class, a second class and a third class according to the reservoir classification standard;
s2, sampling at least one core from the first type, the second type and the third type in the S1 respectively, and performing saturated simulation formation water on the cores with three different pore structure types;
s3, continuing to saturate the original dehydrated and degassed crude oil to the core saturated with the simulated formation water;
s4, performing a tubule experiment to determine CO2Minimum miscible pressure with crude oil;
s5, performing a carbon dioxide flooding experiment, and performing nuclear magnetic resonance T on rock cores under different experimental pressures2Spectrum sampling is carried out, corresponding oil displacement efficiency is calculated, and CO is realized under different pressures of a compact reservoir2Evaluating the dynamic characteristics of large pores and small pores in the oil displacement process.
2. The tight reservoir CO of claim 12The method for evaluating the reservoir driving characteristics is characterized in that a carbon dioxide oil displacement experiment is carried out in S5, and nuclear magnetic resonance T is carried out on rock cores under different experimental pressures2Spectrum sampling, specifically:
s51, raising the experimental pressure to corresponding different gas injection pressures through the intermediate container pressure holding;
s52, injecting carbon dioxide into the core from the inlet end of the core under different gas injection pressures of S51 until the outlet end of the core produces no oil; in S52, the carbon dioxide injection amount and the oil production amount were recorded, and the core after the experiment was sampled by a T2 spectrum.
3. The tight reservoir CO of claim 22The method for evaluating the driving reservoir characteristic is characterized in that the reservoir classification standard in S1 is as follows:
and classifying according to the porosity, permeability, movable fluid saturation, movable fluid porosity, displacement pressure, median pressure, sorting coefficient, pore throat radius, maximum pump-entering saturation, pore throat combination and void type parameters of the core.
4. Dense reservoir CO according to claim 32The method for evaluating the reservoir driving characteristics is characterized in that saturated simulated formation water is performed on cores of three different pore structure types in S2, and specifically comprises the following steps:
firstly, cleaning and drying a rock core, then putting the rock core into a holder, vacuumizing the rock core for 12 hours after confining pressure of 2-3 MPa is added, fully saturating simulated formation water, and carrying out T treatment on the rock core in the state2And (4) spectrum sampling.
5. Compact reservoir CO according to claim 42The method for evaluating the characteristics of reservoir driving is characterized in that a core saturated with simulated formation water in S3 is continuously saturated with original dehydrated and degassed crude oil, and specifically comprises the following steps:
injecting dehydrated and degassed crude oil into the core at the temperature of 60 ℃ at the speed of 0.01mL/min to displace formation water in the core until no water is discharged from an outlet end; and when the oil phase permeability error is measured for 3 times continuously and is less than 5%, stopping injecting the degassed crude oil, and performing T on the core in the state2And (4) spectrum sampling.
6. Compact reservoir CO according to any one of claims 2 to 52The method for evaluating the characteristics of the driving reservoir is characterized in that the corresponding gas injection pressure in S51 comprises the following steps: 6MPa, 12MPa, 18MPa and 22 MPa.
7. The tight reservoir CO of claim 62The method for evaluating driving characteristics of a reservoir, wherein S52 further includes:
and when the outlet end of the core does not produce oil, continuously injecting 2PV carbon dioxide.
8. The method for evaluating the CO2 flooding reservoir production characteristics of the tight reservoir of claim 2, wherein the injection rate of carbon dioxide into the core from the inlet end of the core at different gas injection pressures in S52 is 0.1 mL/min.
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