CN112780242A - Chemical flooding reservoir graded displacement oil extraction method for conglomerate reservoir - Google Patents
Chemical flooding reservoir graded displacement oil extraction method for conglomerate reservoir Download PDFInfo
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- CN112780242A CN112780242A CN201911089604.7A CN201911089604A CN112780242A CN 112780242 A CN112780242 A CN 112780242A CN 201911089604 A CN201911089604 A CN 201911089604A CN 112780242 A CN112780242 A CN 112780242A
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- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
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- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
- E21B43/20—Displacing by water
Abstract
The invention provides a conglomerate oil reservoir chemical flooding reservoir graded displacement oil extraction method, which comprises the following steps: obtaining pore-throat radii of each percolated layer to obtain a plurality of pore-throat radii; acquiring residual resistance coefficients of the displacement medium corresponding to the pore throat radii, and determining seepage resistance corresponding to each pore throat radius according to capillary pressure of the pore throat radii; determining a displacement pressure gradient according to the parameters of an oil reservoir injection-production system; determining injection parameters of the displacement medium according to the displacement pressure gradient and the seepage resistance of the plurality of permeable layers; and injecting the displacement medium into the plurality of permeable layers through the injection well according to the injection parameters of the displacement medium, and displacing the crude oil in the plurality of permeable layers into the oil production well for production. The technical scheme of the application effectively solves the problems that in the related technology, chemical agents in the conglomerate oil reservoir easily enter the large pore throat to form high permeability layer agent channeling and are difficult to enter the middle and small pore throats to displace crude oil in the middle and low permeability layer.
Description
Technical Field
The invention relates to the technical field of oil development, in particular to a chemical flooding reservoir graded displacement oil extraction method for a conglomerate oil reservoir.
Background
Chemical flooding is an oil recovery process that adds chemical agents to the injection water to change the physicochemical properties of the displacement fluid and the interfacial properties between the displacement fluid and the crude oil and rock minerals, thereby facilitating the production of crude oil. The chemical flooding mainly comprises polymer flooding, polymer/surfactant binary composite flooding, surfactant/polymer/alkali ternary composite flooding and the like. Chemical flooding has become an important means for greatly improving the recovery ratio in the later stage of reservoir water flooding development. How to find a more effective method for displacing residual oil after water flooding in the related art is an urgent problem to be solved in chemical flooding.
At present, most of polymer flooding and compound flooding mine field experiments are carried out in a general injection mode, and the recovery ratio of the mine field experiments is improved by 10-20% compared with that of water flooding. However, the injection mode has the defects that the adjustment of the inhalation section is reversed earlier, and the chemical agent enters the high-permeability layer relatively more, so that the fingering phenomenon of the high-permeability layer is stronger; meanwhile, the distribution of the injection amount of the chemical agent is uneven, the cumulative injection amount of the high permeable layer is nearly 2 times of the design value, and the cumulative injection amount of the medium and low permeable layers is lower than the design value. This results in a lower displacement of the low permeability layer, reducing the enhanced recovery rate, and thus affecting the development benefits.
In view of the above problems, the following chemical flooding injection methods have been explored for conventional sandstone reservoirs in recent years:
injecting a multi-stage plug: in the design of the composite slug, under the condition of the same chemical agent dosage, the scheme of adopting the composite main slug with higher polymer concentration, the front polymer profile control slug with smaller slug and the rear polymer protective slug with higher concentration is relatively more economical, but the polymer composite main slug with single molecular weight and concentration has low displacement degree on the conglomerate oil reservoir and small enhanced recovery rate.
② injecting polymer with wide molecular weight: the medium molecular weight polymer with wider molecular weight distribution is adopted for oil displacement, so that polymer molecules can enter pores with different sizes in an oil layer, the inaccessible pore volume of an oil reservoir is reduced, high, medium and low permeability oil layers are well displaced, the swept volume is greatly expanded, and the oil washing efficiency is improved.
③ alternately injecting: mainly refers to the alternating injection of polymer slugs with different relative molecular masses and different mass concentrations in the polymer flooding process and the alternating injection of polymers and a composite system in the composite flooding process. The injection method has certain blindness to the wide molecular weight injection and the alternate injection modes with different concentrations of the polymer of the conglomerate reservoir, the large-pore-throat high-permeability oil channel cannot be blocked to form chemical agent channeling, the pressure rise amplitude is insufficient, the medium-low permeability oil channel cannot be displaced, and the development effect is not ideal.
Indoor experiments show that the polymer flooding adopts a single slug injection mode, and the low-permeability layer is always in a relatively high-pressure state; and an alternate slug injection mode is adopted, the pressure interaction of the high and low permeable layers is dominant, the disturbance of a local pressure field is enhanced, and the displacement degree of the low permeable layer is favorably improved. The chemical flooding injection mode effectively improves the interlayer heterogeneity of high, medium and low permeability reservoir layers in the reservoir and improves the recovery ratio, but compared with the conventional sandstone reservoir, the conglomerate reservoir has different deposition characteristics, complex pore structures and strong heterogeneity on a plane and a vertical section, wherein the reservoir heterogeneity refers to that the oil and gas reservoir undergoes the comprehensive influence of deposition, diagenesis and later-stage tectonic actions in a long geological history, so that the spatial distribution of the reservoir and various internal attributes have extremely-heterogeneous changes. Therefore, in a conglomerate oil reservoir, a chemical agent easily enters a large-pore-throat high-permeability layer to form agent channeling, the chemical agent enters a channel formed by the large-pore-throat high-permeability layer after being injected from an injection well and is extracted from a production well to form an ineffective cycle, the chemical agent is difficult to enter medium and low permeability layers of a medium and small pore throats, oil in the medium and small pore throats is difficult to displace, the swept efficiency is low, and the development effect is not ideal.
Disclosure of Invention
The invention aims to provide a conglomerate oil reservoir chemical flooding reservoir graded displacement oil extraction method, which aims to solve the problems that in the related technology, chemical agents in a conglomerate oil reservoir easily enter a large pore throat to form high-permeability layer agent channeling and are difficult to enter a middle-small pore throat to displace crude oil in a middle-low permeability layer.
In order to achieve the aim, the invention provides a conglomerate oil reservoir chemical flooding reservoir graded displacement oil extraction method, wherein a reservoir is provided with a plurality of permeable layers formed by a plurality of pore throats, a displacement medium is injected through an injection well to respectively displace crude oil in the plurality of permeable layers, a production well produces the crude oil, residual oil after water flooding is left in the permeable layers, and the injection well and the production well are communicated with the permeable layers, which is characterized by comprising the following steps: obtaining pore-throat radii of each percolated layer to obtain a plurality of pore-throat radii; acquiring residual resistance coefficients of the displacement medium corresponding to the pore throat radii, and determining seepage resistance corresponding to each pore throat radius according to capillary pressure of the pore throat radii; determining a displacement pressure gradient according to the parameters of an oil reservoir injection-production system; determining injection parameters of the displacement medium according to the displacement pressure gradient and the seepage resistance of the plurality of permeable layers; and injecting the displacement medium into the plurality of permeable layers through the injection well according to the injection parameters of the displacement medium, and displacing the crude oil in the plurality of permeable layers into the oil production well for production.
Further, the pore throat radius is obtained by mercury intrusion experimental analysis, wherein the mercury intrusion experimental analysis comprises a common mercury intrusion experiment and/or a constant-speed mercury intrusion experiment.
Further, the pore throat radius is obtained according to the following formula:
wherein, PcIs the capillary pressure, sigma is the interfacial tension, theta is the wetting angle of the two-phase fluid interface and the solid phase, r is the capillary radius, which forms the pore throat radius, i.e. the capillaryThe radius is equivalent to the pore throat radius.
Further, the reservoir injection and production system parameters include reservoir formation pressure, injection well flow pressure, production well flow pressure, injection and production well spacing of the injection well and the production well, distance of any point between the injection well and the production well from the injection well, and wellbore radius of the injection well.
Further, the plurality of displacement pressures in the displacement pressure gradient is obtained by the following formula:
wherein G isDTo displace the pressure gradient, PeIs the reservoir formation pressure, PwfFor injection well flow pressure, PinfFor the flow pressure of the oil production well, R is the distance between the injection well and the production well, RiDistance from injection well at any point between injection well and production well, RwIs the wellbore radius of the injection well.
Further, in the case where the wetting angle of the two-phase fluid interface with the solid phase is 0, the percolation resistance is obtained by the following formula:
wherein P is the seepage resistance and R isFFTo determine the residual coefficient of resistance, the displacement medium flows in the permeable layer when the displacement pressure is greater than the percolation resistance.
Further, based on the polymer solution concentration of the displacement medium, the polymer limiting residual resistance coefficient of the displacement medium, and the polymer limiting concentration of the displacement medium.
Further, the residual drag coefficient is obtained by the following equation: rFF＝1+(RFFeq-1)(Cp/Cpeq)exp(1-Cp/Cpeq) (ii) a Wherein R isFFIs the coefficient of residual resistance, RFFeqPolymer ultimate coefficient of residual resistance, C, for displacement mediapConcentration of polymer solution as displacing medium, CpeqIs the polymer limit concentration of the displacement medium.
Further, the polymer limiting concentration of the displacement medium or the polymer limiting residual resistance coefficient of the displacement medium is determined based on the polymer molecular weight and the permeability.
Further, the polymer limit concentration of the displacement medium is obtained by the following formula:
the polymer ultimate residual resistance coefficient of the displacement medium is obtained by the following formula:
wherein M is the polymer molecular weight, KwIs the permeability.
By applying the technical scheme of the invention, a reservoir is provided with a plurality of permeable layers formed by a plurality of pore throats, a displacement medium is injected through an injection well to respectively displace crude oil in the plurality of permeable layers, the crude oil is produced through a production well, residual oil after water flooding is left in the permeable layers, and the injection well and the production well are both communicated with the permeable layers, and the conglomerate oil reservoir chemical flooding reservoir graded displacement oil production method is characterized by comprising the following steps: obtaining pore-throat radii of each percolated layer to obtain a plurality of pore-throat radii; acquiring residual resistance coefficients of the displacement medium corresponding to the pore throat radii, and determining seepage resistance corresponding to each pore throat radius according to capillary pressure of the pore throat radii; determining a displacement pressure gradient according to the parameters of an oil reservoir injection-production system; determining injection parameters of the displacement medium according to the displacement pressure gradient and the seepage resistance of the plurality of permeable layers; and injecting the displacement medium into the plurality of permeable layers through the injection well according to the injection parameters of the displacement medium, and displacing the crude oil in the plurality of permeable layers into the oil production well for production. The injection parameters of the displacement medium can be the injection quantity, speed and concentration of the displacement medium. In the application, when the production pressure difference between the injection well and the oil production well is constant, the displacement medium with higher resistance is difficult to enter the permeable layer with smaller pore throat, so that the displacement medium with higher resistance can only enter the permeable layer with larger pore throat, and the residual oil in the permeable layer with larger pore throat is displaced and is preferentially produced through the oil production well. The displacement pressure gradient is rapidly reduced along with the continuous propulsion of the displacement medium on the permeable stratum with larger pore throat, so that the displacement medium is slowly propelled in the middle of the injection and production well, and the displacement medium is retained and blocks the permeable stratum with larger pore throat. At this point, the concentration of the displacement medium is reduced appropriately, reducing the percolation resistance, allowing the lower resistance displacement medium to enter the permeable formation with a smaller pore throat. Similarly, after the deep part of the stratum is blocked, the concentration of the displacement medium can be reduced in a gradient manner, and the displacement medium with lower resistance enters a permeable layer with a smaller pore throat in a gradient manner, so that the graded displacement of the residual oil is realized, and the residual oil is sequentially extracted through the oil extraction well. Therefore, the injection parameters of the oil displacement medium can be optimized according to the pore-throat distribution characteristics of the conglomerate reservoir and the displacement pressure gradient in the conglomerate reservoir, and the crude oil in the permeable layers is finally displaced. Therefore, the technical scheme effectively solves the problems that in the related technology, chemical agents in the conglomerate oil reservoir easily enter the large pore throat to form high permeability layer agent channeling and are difficult to enter the middle and small pore throats to displace crude oil in the middle and low permeability layers.
Drawings
The accompanying drawings, which are incorporated in and constitute a part of this application, illustrate embodiments of the invention and, together with the description, serve to explain the invention and not to limit the invention. In the drawings:
FIG. 1 shows a schematic diagram of a chemical flooding injection-production well of an embodiment of a conglomerate reservoir chemical flooding reservoir staged displacement oil recovery method according to the present invention;
FIG. 2 shows a schematic pore-throat structure of the conglomerate reservoir chemical flooding reservoir staged displacement oil recovery method of FIG. 1;
FIG. 3 shows a constant-velocity mercury intrusion schematic of the conglomerate reservoir chemical flooding reservoir staged displacement oil recovery method of FIG. 2;
FIG. 4 illustrates a binary composite flooding profile of the conglomerate reservoir chemical flooding reservoir staged displacement oil recovery method of FIG. 1;
FIG. 5 shows a pore-throat diameter distribution histogram of the conglomerate reservoir chemical flooding reservoir staged displacement oil recovery method of FIG. 1;
FIG. 6 shows a displacement pressure gradient profile between injection and production wells of the conglomerate reservoir chemical flooding reservoir staged displacement oil recovery method of FIG. 1; and
fig. 7 shows a schematic of the rock of the conglomerate reservoir chemical flooding reservoir staged displacement oil recovery method of fig. 1.
Wherein the figures include the following reference numerals:
1. no. 1 pore; 2. no. 2 pore space; 3. no. 3 pore space; 4. no. 4 pore space; 6. rock.
Detailed Description
The technical solutions in the embodiments of the present invention will be clearly and completely described below with reference to the drawings in the embodiments of the present invention, and it is obvious that the described embodiments are only a part of the embodiments of the present invention, and not all of the embodiments. The following description of at least one exemplary embodiment is merely illustrative in nature and is in no way intended to limit the invention, its application, or uses. All other embodiments, which can be derived by a person skilled in the art from the embodiments given herein without making any creative effort, shall fall within the protection scope of the present invention.
It is noted that the terminology used herein is for the purpose of describing particular embodiments only and is not intended to be limiting of example embodiments according to the present application. As used herein, the singular forms "a", "an" and "the" are intended to include the plural forms as well, and it should be understood that when the terms "comprises" and/or "comprising" are used in this specification, they specify the presence of stated features, steps, operations, devices, components, and/or combinations thereof, unless the context clearly indicates otherwise.
The relative arrangement of the components and steps, the numerical expressions and numerical values set forth in these embodiments do not limit the scope of the present invention unless specifically stated otherwise. Meanwhile, it should be understood that the sizes of the respective portions shown in the drawings are not drawn in an actual proportional relationship for the convenience of description. Techniques, methods, and apparatus known to those of ordinary skill in the relevant art may not be discussed in detail but are intended to be part of the specification where appropriate. In all examples shown and discussed herein, any particular value should be construed as merely illustrative, and not limiting. Thus, other examples of the exemplary embodiments may have different values. It should be noted that: like reference numbers and letters refer to like items in the following figures, and thus, once an item is defined in one figure, further discussion thereof is not required in subsequent figures.
As shown in fig. 1, the present embodiment provides a conglomerate reservoir chemical flooding reservoir graded displacement oil recovery method. The reservoir stratum is provided with a plurality of permeable layers formed by a plurality of pore throats, a displacement medium is injected through an injection well to respectively displace crude oil in the plurality of permeable layers, the crude oil is extracted through a production well, residual oil after water flooding is left in the permeable layers, and the injection well and the production well are communicated with the permeable layers, and the chemical flooding reservoir stratum graded displacement oil extraction method for the conglomerate oil reservoir is characterized by comprising the following steps of: obtaining pore-throat radii of each percolated layer to obtain a plurality of pore-throat radii; acquiring residual resistance coefficients of the displacement medium corresponding to the pore throat radii, and determining seepage resistance corresponding to each pore throat radius by combining capillary pressure of the pore throat radii; determining a displacement pressure gradient according to the parameters of an oil reservoir injection-production system; determining injection parameters of the displacement medium according to the displacement pressure gradient and the seepage resistance of the plurality of permeable layers; and injecting the displacement medium into the plurality of permeable layers through the injection well according to the injection parameters of the displacement medium, and displacing the crude oil in the plurality of permeable layers into the oil production well for production.
By applying the technical scheme of the embodiment, the injection parameters of the displacement medium can be the injection amount, the injection speed and the injection concentration of the displacement medium. In this embodiment, when the production pressure difference between the injection well and the production well is constant, the higher resistance displacement medium is difficult to enter the permeable formation with the smaller pore throat, so that the higher resistance displacement medium can only enter the permeable formation with the larger pore throat, and the residual oil in the permeable formation with the larger pore throat is displaced to the production well for preferential production. The displacement pressure gradient is rapidly reduced along with the continuous propulsion of the displacement medium, so that the displacement medium is slowly propelled in the middle of the injection and production well, and the displacement medium is retained and blocks a permeable layer with a larger throat. At this point, the concentration of the displacement medium is reduced appropriately, reducing the percolation resistance, allowing the lower resistance displacement medium to enter the permeable formation with a smaller pore throat. Similarly, after the deep part of the stratum is blocked, the concentration of the displacement medium can be reduced in a gradient manner, so that the displacement medium with lower resistance enters a permeable layer with a smaller pore throat in a gradient manner, thereby realizing the graded displacement of the residual oil, and sequentially extracting the residual oil through the oil production well. Therefore, the injection parameters of the oil displacement medium can be optimized according to the pore throat distribution characteristics in the oil layer of the chemical flooding oil reservoir and the displacement pressure gradient in the conglomerate oil reservoir, and finally the crude oil in the permeable layers is displaced. Therefore, the technical scheme of the embodiment effectively solves the problems that in the related technology, chemical agents in the conglomerate oil reservoir easily enter the large pore throat to form high permeability layer agent channeling and are difficult to enter the middle and small pore throats to displace crude oil in the middle and low permeability layers.
It should be noted that, in the present embodiment, the pore throat radii are all different, the sizes of the permeation layers are all different, the pore throat size is determined according to the pore throat radius, and the permeation layer size is determined according to the pore throat radius size. For example, a large pore throat radius belongs to a high permeable layer, a small pore throat radius belongs to a low permeable layer, and a medium permeable layer between the large pore throat radius and the small pore throat radius.
In this embodiment, the displacement pressure gradient is determined by the production pressure difference and the injection-production well spacing, when displacement is performed by using the displacement medium, the injection-production well spacing is fixed and difficult to change, and the displacement pressure can be adjusted only by regulating the production pressure difference, which is related to the injection rate, the reservoir physical properties, and the displacement medium. The seepage resistance is determined by the pore throat radius in the reservoir, the drag coefficient of the displacement medium. The influence factors of the displacement pressure gradient and the seepage resistance are comprehensively considered, the injection-production well spacing and the reservoir characteristics are difficult to change in the process that the displacement medium is displaced by chemical flooding, and the adjustment range of the injection speed of the displacement medium is limited, so that the displacement pressure and the seepage resistance are changed by adjusting the interfacial tension and the medium concentration of the injected medium.
As shown in fig. 2 and 3, the pore throat radius was obtained by mercury intrusion experimental analysis, wherein the mercury intrusion experimental analysis includes a general mercury intrusion experiment and a constant-rate mercury intrusion experiment. It should be noted that in the ordinary mercury-pressing experiment, different pressure points are set from low to high under a constant mercury-feeding pressure, the radius of the pore throat is calculated according to the mercury-feeding amount of each pressure point, and the volume controlled by the pore throat corresponding to the mercury-feeding pressure is calculated by measuring the mercury-feeding amount; through mercury inlet pressure experiments, the pore throat size distribution in the rock sample can be obtained. The constant-speed mercury pressing experiment is carried out at a very low mercury feeding speed so as to ensure quasi-static mercury feeding. And separating the throat from the pores in the rock by detecting pressure fluctuation in the mercury inlet process, and directly measuring the pores of the porous medium and the size and the number of the throat to obtain the volume of the throat and the volume of the pores in the pores. The mercury feed pressure in the mercury intrusion experiment of this example is equivalent to the capillary pressure.
As shown in fig. 2 and 3, specifically, fig. 3 shows the relationship between the rise and fall of the capillary pressure and the corresponding mercury feeding amount during the mercury intrusion process in the constant-speed mercury intrusion experiment. When mercury firstly enters the entrance throat (position shown by arrow in figure 2) of No. 1 pore, the mercury pressure gradually rises to a certain value, the mercury breaks through the entrance throat and enters No. 1 pore, the mercury pressure immediately drops, the first pressure drop point in fig. 3, after the mercury inlet pressure corresponding to the No. 1 pore is reached, the mercury gradually fills the No. 1 pore, the mercury inlet pressure gradually rises, because the throat between aperture No. 1 and aperture No. 2 is larger than the throat between aperture No. 1 and aperture No. 4, when the mercury inlet pressure reaches the pressure capable of entering the No. 2 pore, the mercury enters the No. 2 pore from the throat between the No. 1 pore and the No. 2 pore, the mercury inlet pressure is reduced again to generate a second secondary pressure drop point, and so on, the mercury gradually fills all the pores controlled by the main throat until the mercury inlet pressure is increased to the pressure at the main throat to form a complete pore throat unit. Wherein, V1PIs number 1 pore volume; v2PIs number 2 pore volume; v3PIs number 3 pore volume; v4PNumber 4 pore volume; vt1Before entering No. 4 pore, the throat volume is entered; vt2Before entering the next pore, the throat volume is entered; vTIs the sum of the total pore volume and the total throat volume.
In other embodiments not shown in the figures, the mercury intrusion experimental analysis includes a normal mercury intrusion experiment or a constant rate mercury intrusion experiment.
In this example, the basic principle of mercury intrusion experimental analysis is as follows:
a clean capillary tube is inserted into a container containing a free liquid surface, whereupon the water is subjected to an upward applied pressure, surface tension, due to the surface tension. The surface of the wetting phase rises to a certain height along the capillary wall. Conversely, if the capillary tube is inserted into a non-wetting phase (e.g., mercury), the liquid interface within the tube is convex and the liquid is subjected to a downward additional pressure. The non-wetting phase level is lowered by a certain height. Due to the effect of interfacial tension and wettability, unequal pressures of the fluids occur at the two sides of the interface between the fluids, which is referred to as capillary or capillary pressure, or simply capillary pressure.
The rock pore space is considered to be composed of bundles of parallel hairs of equal diameter, in which the multiphase fluid flows. Capillary forces are generated at the phase interface due to selective wetting of the rock by the fluid and surface tension effects between the phases. Capillary forces are an additional pressure that balances the difference between the non-wet and wet phase pressures across the meniscus in the capillary.
The pore throat radius is obtained according to the following formula:
wherein, PcIs the capillary pressure, σ is the interfacial tension, θ is the wetting angle of the two-phase fluid interface and the solid phase, r is the capillary radius, which forms the pore throat radius. In this example, the "two-phase fluid" is the displacement medium and oil, and the "solid phase" is the reservoir formation. In this embodiment, a certain area in the conglomerate reservoir with a flat terrain, an average ground elevation of 267m and a ground relative height difference of less than 10m is selected. As shown in fig. 5, a core sample is selected from the block, and the microscopic pore throat radius and distribution condition in the oil layer can be obtained through mercury intrusion experimental analysis.
In this embodiment, the reservoir injection and production system parameters include reservoir formation pressure, injection well flow pressure, production well flow pressure, injection and production well spacing for the injection and production wells, the distance between any point between the injection and production wells from the injection well, and the wellbore radius of the injection well.
In this embodiment, the plurality of displacement pressures in the displacement pressure gradient is obtained by the following formula:
wherein G isDTo displace the pressure gradient, PeIs the reservoir formation pressure, PwfFor injection well flow pressure, PinfFor the flow pressure of the oil production well, R is the distance between the injection well and the production well, RiDistance from injection well at any point between injection well and production well, RwIs the wellbore radius of the injection well. The displacement mode of this embodiment may be chemical flooding, or water flooding, and when chemical flooding is adopted, the displacement medium is preferably a polymer solution. And (3) calculating the minimum seepage pressure difference limit according to the pressure system parameters and the displacement pressure formula of the water flooding and chemical flooding stages of the block, and particularly referring to the following tables 1 and 2.
TABLE 1 Displacement pressure gradient between injection and production wells during water flooding of this block
| GD(MPa/m) | Pe(MPa) | Pwf(MPa) | Pinf(MPa) | rw(m) | R(m) | ri(m) |
| 0.0947 | 14 | 6 | 18 | 0.1 | 150 | 10 |
| 0.0463 | 14 | 6 | 18 | 0.1 | 150 | 20 |
| 0.0328 | 14 | 6 | 18 | 0.1 | 150 | 30 |
| 0.0271 | 14 | 6 | 18 | 0.1 | 150 | 40 |
| 0.0245 | 14 | 6 | 18 | 0.1 | 150 | 50 |
| 0.0235 | 14 | 6 | 18 | 0.1 | 150 | 60 |
| 0.0237 | 14 | 6 | 18 | 0.1 | 150 | 70 |
| 0.0249 | 14 | 6 | 18 | 0.1 | 150 | 80 |
| 0.0274 | 14 | 6 | 18 | 0.1 | 150 | 90 |
| 0.0315 | 14 | 6 | 18 | 0.1 | 150 | 100 |
| 0.0386 | 14 | 6 | 18 | 0.1 | 150 | 110 |
| 0.0515 | 14 | 6 | 18 | 0.1 | 150 | 120 |
| 0.0798 | 14 | 6 | 18 | 0.1 | 150 | 130 |
| 0.1777 | 14 | 6 | 18 | 0.1 | 150 | 140 |
TABLE 2 Displacement pressure gradient between injection and production wells during chemical flooding of this block
| GD(MPa/m) | Pe(MPa) | Pwf(MPa) | Pinf(MPa) | rw(m) | R(m) | ri(m) |
| 0.1855 | 14 | 2 | 22 | 0.1 | 150 | 10 |
| 0.0884 | 14 | 2 | 22 | 0.1 | 150 | 20 |
| 0.0609 | 14 | 2 | 22 | 0.1 | 150 | 30 |
| 0.0490 | 14 | 2 | 22 | 0.1 | 150 | 40 |
| 0.0431 | 14 | 2 | 22 | 0.1 | 150 | 50 |
| 0.0404 | 14 | 2 | 22 | 0.1 | 150 | 60 |
| 0.0399 | 14 | 2 | 22 | 0.1 | 150 | 70 |
| 0.0411 | 14 | 2 | 22 | 0.1 | 150 | 80 |
| 0.0443 | 14 | 2 | 22 | 0.1 | 150 | 90 |
| 0.0502 | 14 | 2 | 22 | 0.1 | 150 | 100 |
| 0.0605 | 14 | 2 | 22 | 0.1 | 150 | 110 |
| 0.0795 | 14 | 2 | 22 | 0.1 | 150 | 120 |
| 0.1218 | 14 | 2 | 22 | 0.1 | 150 | 130 |
| 0.2685 | 14 | 2 | 22 | 0.1 | 150 | 140 |
It can be seen from tables 1 and 2 that a pressure drop funnel exists between the injection well and the production well of the oil reservoir, the displacement pressure gradient in the near wellbore region is large, the chemical agent is easy to enter, and the displacement pressure gradient in the deep part of the stratum, i.e. the distance between the injection well and the production well is minimum.
As shown in fig. 6, the minimum displacement pressure gradient of the block is 0.028MPa/m when the injection-production differential pressure is 12MPa at the injection-production well spacing of 150 m; when the injection-production pressure difference is 20MPa, the minimum displacement pressure gradient is 0.04 MPa/m.
In this embodiment, the water-driving seepage resistance is determined by the interfacial tension and the capillary radius, and the capillary resistances with different pore-throat radii can be calculated by the calculation formula of the capillary pressure Pc. The seepage resistance of chemical flooding needs to consider not only capillary resistance but also the residual resistance coefficient generated by chemical agents. When the wetting angle between the interface of the two-phase fluid and the solid phase is 0, the seepage resistance is obtained by the following formula:
wherein P is the seepage resistance and R isFFTo determine the residual coefficient of resistance, the displacement medium flows in the permeable layer when the displacement pressure is greater than the percolation resistance.
In the embodiment, when the injection-production differential pressure is increased from 12MPa to 20MPa for a well pattern with the injection-production well spacing of 150m, the minimum displacement pressure isThe Gradient (GD) increased from 0.031MPa/m to 0.043 MPa/m. When the radius of the pore throat is less than 3um in water flooding, the permeability is 50mD, the capillary pressure is more than 0.05MPa, and the displacement pressure gradient is only 0.031MPa/m, so that the water flooding can only displace a permeable layer with the pore throat radius more than 3um and the permeability of 50 mD. Therefore, after long-time water injection development, the production degree of a high-permeability layer is high, the saturation degree of residual oil is low, a water flow dominant channel is formed, and the phenomenon of ineffective circulation of water injection is caused. In this example, the polymer solution concentration in the displacement medium, the polymer limiting concentration of the displacement medium, and the polymer limiting residual drag coefficient of the displacement medium are used. In the present embodiment, the residual drag coefficient is obtained by the following equation: rFF＝1+(RFFeq-1)(Cp/Cpeq)exp(1-Cp/Cpeq) (ii) a Wherein, R isFFIs the coefficient of residual resistance, RFFeqLimiting residual coefficient of resistance of polymer, C, for displacing mediapConcentration of polymer solution as displacing medium, CpeqIs the polymer limit concentration of the displacement medium.
Note that the polymer concentration C as a function of the displacement mediumpIncrease of (2), coefficient of residual resistance RFFIs continuously increased when CpAfter increasing to a certain value, RFFThe increase was slow and gradually tended to be constant. The polymer concentration at a constant residual drag coefficient is referred to as the polymer limit concentration C of the displacement mediumpeqThe residual coefficient of resistance at constant is referred to as the polymer limiting residual coefficient of resistance R of the displacement mediumFFeq. In this example, the polymer limiting concentration of the displacement medium or the polymer limiting residual drag coefficient of the displacement medium is determined based on the polymer molecular weight and permeability.
In this example, the polymer limiting concentration of the displacement medium is obtained by the following equation:
the polymer ultimate residual resistance coefficient of the displacement medium is obtained by the following formula:
wherein M is the polymer molecular weight, KwIs the permeability.
It should be noted that the residual resistance coefficient of the polymer solution flowing through the permeation layers is greatly affected by the polymer concentration, the polymer molecular weight, the permeability of the permeation layers, and the like. The study shows that RFFWith CPIs increased when C is increasedPAfter increasing to a certain value, RFFThe increase is slow and gradually tends to be constant; as the molecular weight M of the polymer increases, the residual drag coefficient RFFAnd is increased; permeability K in multiple permeation layers at the same molecular weight and concentration of the polymerWThe lower the residual drag coefficient RFFThe larger.
As shown in fig. 7, according to capillary theory, the pore space of multiple permeable layers of a conglomerate reservoir may be equivalent to the result of the cooperation of numerous capillaries of the same radius, tortuosity, and length. When n capillaries of the same tortuosity are present simultaneously in the reservoir rock 6, the permeability of the multiple permeable layers in the reservoir can be expressed as:
wherein k is the effective permeability of the permeation layer;
effective porosity of the permeable layer; r is the average capillary radius; t is the tortuosity of the capillary; α is a unit conversion factor. Specifically, please refer to the article "predicting permeability of reservoir with neural network technology" published by the authors as "chemical industry management" 2014, 11 th page 93 for explaination.
The chemical flooding achieves the purposes of plugging a high-permeability layer and displacing oil in a low-permeability layer by increasing the resistance coefficient of a displacement medium and reducing the interfacial tension. The block chemical flooding stage adopts a polymer front-mounted slug, a binary slug early stage, a binary slug middle stage, a binary slug late stage and a subsequent protective slug. The seepage resistance of the chemical flooding was calculated by the above formula, see tables 3 to 6 below.
TABLE 3 seepage resistance of the chemically-driven pre-slugs in this block at different pore throat radii
| P(MPa) | r(um) | Kw(mD) | σ(mN/m) | Pc(MPa) | RFF |
| 0.1 | 0.03 | 0.076 | 1.520 | ||
| 0.5 | 0.95 | 0.076 | 0.304 | ||
| 61.304 | 1.0 | 4.36 | 0.076 | 0.152 | 403.32 |
| 5.994 | 2.0 | 20.03 | 0.076 | 0.076 | 78.87 |
| 2.146 | 3.0 | 48.88 | 0.076 | 0.051 | 42.36 |
| 1.128 | 4.0 | 92.05 | 0.076 | 0.038 | 29.67 |
| 0.710 | 5.0 | 150.39 | 0.076 | 0.030 | 23.34 |
| 0.495 | 6.0 | 224.60 | 0.076 | 0.025 | 19.55 |
| 0.194 | 10.0 | 691.01 | 0.076 | 0.015 | 12.79 |
| 0.098 | 15.0 | 1686.12 | 0.076 | 0.010 | 9.67 |
| 0.062 | 20.0 | 3175.06 | 0.076 | 0.008 | 8.12 |
| 0.044 | 25.0 | 5187.46 | 0.076 | 0.006 | 7.16 |
In table 3, polymer pre-slugs: the injected polymer solution has a molecular weight of 2500 ten thousand and a concentration of 1500 mg/L. Near wellbore area may enter a formation with a pore throat radius of 6um, with a permeability of 500mD, as the polymer solution advances in the formation. The displacement pressure gradient of the oil reservoir is rapidly reduced, when the injection-production pressure difference of the oil reservoir reaches 20MPa, the minimum displacement pressure gradient in the middle of the oil reservoir is 0.039MPa/m, the seepage resistance of a displacement medium in the oil layer with the pore throat radius of 25 mu m reaches 0.044MPa, the permeability is 5000mD, and the seepage dominant channel with the permeability of the block ranging from 500mD to 5000mD can be effectively plugged at the deep part of the stratum. The oil deposit shows that the oil production quantity is gradually increased along with the injection of the chemical agent, the oil deposit begins to fall back after reaching a certain peak value, when the oil extraction speed is less than 0.5 percent, the development benefit is poor, and the next slug is shifted to.
TABLE 4 seepage resistance at different pore throat radii at the earlier stages of chemical flooding binary main segment plug in this block
| P(MPa) | r(um) | Kw(mD) | σ(mN/m) | Pc(MPa) | RFF |
| 0.1 | 0.03 | 0.005 | 0.100 | ||
| 0.5 | 0.95 | 0.005 | 0.020 | ||
| 4.033 | 1.0 | 4.36 | 0.005 | 0.010 | 403.32 |
| 0.394 | 2.0 | 20.03 | 0.005 | 0.005 | 78.87 |
| 0.141 | 3.0 | 48.88 | 0.005 | 0.003 | 42.36 |
| 0.074 | 4.0 | 92.05 | 0.005 | 0.003 | 29.67 |
| 0.047 | 5.0 | 150.39 | 0.005 | 0.002 | 23.34 |
| 0.033 | 6.0 | 224.60 | 0.005 | 0.002 | 19.55 |
| 0.013 | 10.0 | 691.01 | 0.005 | 0.001 | 12.79 |
| 0.006 | 15.0 | 1686.12 | 0.005 | 0.001 | 9.67 |
| 0.004 | 20.0 | 3175.06 | 0.005 | 0.001 | 8.12 |
| 0.003 | 25.0 | 5187.46 | 0.005 | 0.000 | 7.16 |
In table 4, the binary slug earlier stage: after the dominant channel is effectively blocked, the minimum displacement pressure gradient of the oil reservoir is kept at 0.039MPa/m, and surfactant and 5 multiplied by 10 interfacial tension are added on the basis of injecting polymer solution-3The high permeability layer has the advantages that the concentration of mN/m is 3000mg/L, the seepage resistance is reduced, the pore throat radius is 5-6 um, the seepage resistance is reduced to 0.04MPa from 0.60MPa, the permeability is 100mD-300mD, and a displacement medium can enter the deep part of an oil layer to effectively displace residual oil. And similarly, when the oil extraction speed is less than 0.5%, the next slug is shifted. The molecular weight of the polymer in Table 4 is 2500 ten thousand, and the concentration is 1500 mg/L; surfactant interfacial tension 5X 10-3mN/m, concentration 3000 mg/L.
TABLE 5 seepage resistance at different pore throat radii in the middle of the chemical flooding binary main segment plug in this block
| P(MPa) | r(um) | Kw(mD) | σ(mN/m) | Pc(MPa) | RFF |
| 0.1 | 0.03 | 0.005 | 0.1000 | ||
| 1.3941 | 0.5 | 0.95 | 0.005 | 0.0200 | 69.70 |
| 0.2682 | 1.0 | 4.36 | 0.005 | 0.0100 | 26.82 |
| 0.0704 | 2.0 | 20.03 | 0.005 | 0.0050 | 14.07 |
| 0.0351 | 3.0 | 48.88 | 0.005 | 0.0033 | 10.52 |
| 0.0220 | 4.0 | 92.05 | 0.005 | 0.0025 | 8.80 |
| 0.0155 | 5.0 | 150.39 | 0.005 | 0.0020 | 7.75 |
| 0.0117 | 6.0 | 224.60 | 0.005 | 0.0017 | 7.04 |
| 0.0055 | 10.0 | 691.01 | 0.005 | 0.0010 | 5.53 |
| 0.0031 | 15.0 | 1686.12 | 0.005 | 0.0007 | 4.67 |
| 0.0021 | 20.0 | 3175.06 | 0.005 | 0.0005 | 4.19 |
| 0.0015 | 25.0 | 5187.46 | 0.005 | 0.0004 | 3.86 |
In table 5, the medium binary slug phase: when the high permeable layer is blocked, the surfactant is injected continuously to maintain the concentration of the polymer and reduce the molecular weight of the polymer. The seepage resistance is reduced to 1500 ten thousand from 2500 ten thousand, the seepage resistance of a high-permeability layer with the pore throat radius of 3-4 um is reduced to 0.03MPa from 0.11MPa, the permeability is 50mD-100mD, and a displacement medium can enter the deep part of an oil layer to effectively drive residual oil. And similarly, when the oil extraction speed is less than 0.5%, the next slug is shifted. It should be noted that: the molecular weight of the polymer in Table 5 is 1500 ten thousand, and the concentration is 1500 mg/L; surfactant interfacial tension 5X 10-3mN/m, concentration 3000 mg/L.
TABLE 6 seepage resistance at different pore throat radii later in the chemical flooding binary main plug in this block
| P(MPa) | r(um) | Kw(mD) | σ(mN/m) | Pc(MPa) | RFF |
| 12.9550 | 0.1 | 0.03 | 0.005 | 0.1000 | 129.55 |
| 0.2512 | 0.5 | 0.95 | 0.005 | 0.0200 | 12.56 |
| 0.0779 | 1.0 | 4.36 | 0.005 | 0.0100 | 7.79 |
| 0.0276 | 2.0 | 20.03 | 0.005 | 0.0050 | 5.52 |
| 0.0157 | 3.0 | 48.88 | 0.005 | 0.0033 | 4.70 |
| 0.0106 | 4.0 | 92.05 | 0.005 | 0.0025 | 4.25 |
| 0.0079 | 5.0 | 150.39 | 0.005 | 0.0020 | 3.96 |
| 0.0063 | 6.0 | 224.60 | 0.005 | 0.0017 | 3.75 |
| 0.0033 | 10.0 | 691.01 | 0.005 | 0.0010 | 3.27 |
| 0.0020 | 15.0 | 1686.12 | 0.005 | 0.0007 | 2.96 |
| 0.0014 | 20.0 | 3175.06 | 0.005 | 0.0005 | 2.78 |
| 0.0011 | 25.0 | 5187.46 | 0.005 | 0.0004 | 2.65 |
In table 6, the binary post-slug period: after the medium and high permeable layer is blocked, the surfactant is continuously injected, the molecular weight and concentration of the polymer are reduced from 1500 ten thousand to 1000 ten thousand, the concentration is reduced from 1500mg/L to 1000mg/L, the seepage resistance is reduced again, the seepage resistance of the medium and low permeable layer with the pore throat radius of 2-3 um is reduced from 0.11MPa to 0.03MPa, the permeability is 30mD-50mD, and the displacement medium can enter the deep part of an oil layer to effectively drive the residual oil. And similarly, when the oil extraction speed is less than 0.5%, the next slug is shifted. It should be noted that: the molecular weight of the polymer is 1000 ten thousand, and the concentration is 1000 mg/L; surfactant interfacial tension 5X 10-3mN/m, concentration 2000 mg/L.
Polymer protective slugs: the injected polymer solution has the molecular weight of 1000 ten thousand and the concentration of 1000mg/L, so that the seepage resistance is increased, and the subsequent water drive channeling is prevented.
According to the graded displacement oil extraction method for the conglomerate oil reservoir chemical flooding reservoir, displacement media and injection parameters in different permeable layers corresponding to different pore throats are displaced according to the relationship among pore throat distribution characteristics, displacement pressure gradient and seepage resistance in the reservoir. The method of the embodiment has clear principle, high quantification and operability and convenient use, and provides reliable basis for optimization of chemical flooding parameters and on-site tracking adjustment. The technical scheme of the embodiment can also solve the problems of strong heterogeneity, small displacement using range and non-ideal development effect of chemical flooding in the conglomerate reservoir layer.
As shown in FIG. 4, the oil-containing area of the block was 0.44km2Geological reserve 54.0 × 104t. A polymer/surfactant binary combination flooding test is carried out by adopting a five-point method well pattern and an 8-injection 13-well group with the well spacing of 150 m. By implementing the technical scheme of the embodiment, chemical flooding is started in 8 months in 2010, 77.6 million chemical agents are added in 4 months in 2019, the chemical agents account for 79.5% of the total design amount, and the stage extraction degree is 15.9%, wherein the extraction degree of the front slug stage is 2.6%, the extraction degree of the early stage of the binary slug is 2.9%, the extraction degree of the middle stage of the binary slug is 5.6%, and the extraction degree of the later stage of the binary slug has reached 4.8%. Therefore, the oil recovery method of gradient injection and graded displacement is adopted for the conglomerate oil reservoir, and the recovery ratio can be greatly improved.
In the description of the present invention, it is to be understood that the orientation or positional relationship indicated by the orientation words such as "front, rear, upper, lower, left, right", "lateral, vertical, horizontal" and "top, bottom", etc. are usually based on the orientation or positional relationship shown in the drawings, and are only for convenience of description and simplicity of description, and in the case of not making a reverse description, these orientation words do not indicate and imply that the device or element being referred to must have a specific orientation or be constructed and operated in a specific orientation, and therefore, should not be considered as limiting the scope of the present invention; the terms "inner and outer" refer to the inner and outer relative to the profile of the respective component itself.
Spatially relative terms, such as "above … …," "above … …," "above … …," "above," and the like, may be used herein for ease of description to describe one device or feature's spatial relationship to another device or feature as illustrated in the figures. It will be understood that the spatially relative terms are intended to encompass different orientations of the device in use or operation in addition to the orientation depicted in the figures. For example, if a device in the figures is turned over, devices described as "above" or "on" other devices or configurations would then be oriented "below" or "under" the other devices or configurations. Thus, the exemplary term "above … …" can include both an orientation of "above … …" and "below … …". The device may be otherwise variously oriented (rotated 90 degrees or at other orientations) and the spatially relative descriptors used herein interpreted accordingly.
It should be noted that the terms "first", "second", and the like are used to define the components, and are only used for convenience of distinguishing the corresponding components, and the terms have no special meanings unless otherwise stated, and therefore, the scope of the present invention should not be construed as being limited.
The above description is only a preferred embodiment of the present invention and is not intended to limit the present invention, and various modifications and changes may be made by those skilled in the art. Any modification, equivalent replacement, or improvement made within the spirit and principle of the present invention should be included in the protection scope of the present invention.
Claims (10)
1. A conglomerate reservoir chemical flooding reservoir staged displacement oil recovery method, said reservoir having a plurality of permeable zones formed with a plurality of pore throats, injecting a displacement medium through an injection well to displace crude oil within a plurality of said permeable zones, respectively, producing oil through a production well, leaving a water-displaced residual oil in said permeable zones, said injection well and said production well both being in communication with said permeable zones, said conglomerate reservoir chemical flooding reservoir staged displacement oil recovery method comprising the steps of:
obtaining pore-throat radii for each of the permeable layers to obtain a plurality of pore-throat radii;
obtaining residual resistance coefficients of the displacement medium corresponding to the pore throat radii, and determining seepage resistance corresponding to each pore throat radius according to capillary pressure of the pore throat radii;
determining a displacement pressure gradient according to the parameters of an oil reservoir injection-production system;
determining injection parameters of the displacement medium according to the displacement pressure gradient and the seepage resistance of the plurality of permeable layers;
and injecting the displacement medium into a plurality of permeable layers through the injection well according to the injection parameters of the displacement medium, and displacing the crude oil in the permeable layers into the oil production well for production.
2. The conglomerate reservoir chemical flooding reservoir staged displacement oil recovery method according to claim 1, wherein the pore throat radius is obtained by mercury intrusion experimental analysis, wherein the mercury intrusion experimental analysis comprises a normal mercury intrusion experiment and/or a constant rate mercury intrusion experiment.
3. The conglomerate reservoir chemical flooding reservoir staged displacement oil recovery method of claim 2, wherein the pore throat radius is obtained according to the following formula:
wherein, the PcIs capillary pressure, the σ is interfacial tension, the θ is wetting angle of the two-phase fluid interface and the solid phase, the r is capillary radius, the capillary radius forming the pore throat radius.
4. The conglomerate reservoir chemical flooding reservoir staged displacement oil recovery method of claim 1, wherein the reservoir injection and production system parameters include reservoir formation pressure, injection well flow pressure, production well flow pressure, injection and production well spacing of injection and production wells, distance of any point between injection and production wells from injection well, and wellbore radius of injection well.
5. The conglomerate reservoir chemical flooding reservoir staged displacement oil recovery method of claim 1, wherein the plurality of displacement pressures in the displacement pressure gradient is obtained by the following formula:
wherein, G isDTo displace the pressure gradient, said PeIs reservoir formation pressure, PwfFor injection well flow pressure, said PinfFor the flow pressure of the oil production well, R is the injection and production well spacing, RiThe distance between any point between the injection well and the oil production well and the injection well, RwIs the wellbore radius of the injection well.
6. The method for graded displacement oil recovery of a conglomerate reservoir chemical flooding reservoir as claimed in claim 3, characterized in that, in the case that the wetting angle of the two-phase fluid interface and the solid phase is 0, the seepage resistance is obtained by the following formula:
wherein P is the seepage resistance and R isFFAnd when the displacement pressure is larger than the seepage resistance, the displacement medium flows in the permeation layer, and r is the capillary radius.
7. A conglomerate reservoir chemical flooding reservoir staged displacement oil recovery method according to claim 6, characterized in that the residual resistance coefficient is determined from the polymer solution concentration of the displacement medium, the polymer limiting residual resistance coefficient of the displacement medium and the polymer limiting concentration of the displacement medium.
8. The conglomerate reservoir chemical flooding reservoir staged displacement oil recovery method according to claim 6, wherein the residual drag coefficient is obtained by the following formula:
RFF＝1+(RFFeq-1)(Cp/Cpeq)exp(1-Cp/Cpeq)；
wherein, R isFFIs the residual drag coefficient, said RFFeqThe ultimate coefficient of residual resistance of the polymer, C, for the displacement mediumpIs the polymer solution concentration of the displacement medium, CpeqIs the polymer limit concentration of the displacement medium.
9. A conglomerate reservoir chemical flooding reservoir staged displacement oil recovery method according to claim 8, characterized in that the polymer limiting concentration of the displacement medium or the polymer limiting residual resistance coefficient of the displacement medium is determined in dependence of polymer molecular weight and permeability.
10. The conglomerate reservoir chemical flooding reservoir staged displacement oil recovery method of claim 9, wherein,
the displacement medium has a polymer limit concentration obtained by the following formula:
the polymer ultimate residual resistance coefficient of the displacement medium is obtained by the following formula:
wherein M is the polymer molecular weight and K iswIs the permeability.
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