CN116066045A - Thermal recovery method for improving recovery ratio of low-permeability heavy oil reservoir - Google Patents

Thermal recovery method for improving recovery ratio of low-permeability heavy oil reservoir Download PDF

Info

Publication number
CN116066045A
CN116066045A CN202310353139.3A CN202310353139A CN116066045A CN 116066045 A CN116066045 A CN 116066045A CN 202310353139 A CN202310353139 A CN 202310353139A CN 116066045 A CN116066045 A CN 116066045A
Authority
CN
China
Prior art keywords
steam
injection
oil
carbon dioxide
displacement agent
Prior art date
Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
Granted
Application number
CN202310353139.3A
Other languages
Chinese (zh)
Other versions
CN116066045B (en
Inventor
张超
刘雅莉
李兆敏
李宾飞
顾子涵
李鹏飞
吴明轩
张德心
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
China University of Petroleum East China
Original Assignee
China University of Petroleum East China
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by China University of Petroleum East China filed Critical China University of Petroleum East China
Priority to CN202310353139.3A priority Critical patent/CN116066045B/en
Publication of CN116066045A publication Critical patent/CN116066045A/en
Application granted granted Critical
Publication of CN116066045B publication Critical patent/CN116066045B/en
Active legal-status Critical Current
Anticipated expiration legal-status Critical

Links

Images

Classifications

    • 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
    • E21B43/24—Enhanced recovery methods for obtaining hydrocarbons using heat, e.g. steam injection
    • 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
    • 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
    • E21B43/164—Injecting CO2 or carbonated water
    • Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
    • Y02P—CLIMATE CHANGE MITIGATION TECHNOLOGIES IN THE PRODUCTION OR PROCESSING OF GOODS
    • Y02P90/00—Enabling technologies with a potential contribution to greenhouse gas [GHG] emissions mitigation
    • Y02P90/70—Combining sequestration of CO2 and exploitation of hydrocarbons by injecting CO2 or carbonated water in oil wells

Abstract

The invention belongs to the technical field of oil and gas field development engineering, and particularly relates to a thermal recovery method for improving the recovery ratio of a low-permeability heavy oil reservoir. The thermal recovery method for improving the recovery ratio of the low-permeability heavy oil reservoir comprises the following steps: (1) a steam flooding injection stage; (2) carbon dioxide and steam injection stage; (3) an oil displacement agent slug injection stage; (4) carbon dioxide assisted steam flooding injection stage. The method is suitable for development of low-permeability heavy oil reservoirs, the carbon dioxide and the oil displacement agent are used for assisting steam flooding in a synergistic manner, the flowing capacity and the flowing distance of heavy oil in a stratum are improved, the long-distance heat transfer capacity of steam is enhanced, the ineffective heat dissipation of the steam can be reduced, the heat wave and the volume of the steam can be enlarged, the viscosity of the heavy oil is reduced, and the recovery degree of the heavy oil is improved.

Description

Thermal recovery method for improving recovery ratio of low-permeability heavy oil reservoir
Technical Field
The invention belongs to the technical field of oil and gas field development engineering, and particularly relates to a thermal recovery method for improving the recovery ratio of a low-permeability heavy oil reservoir.
Background
With the deep exploration of oil and gas fields, the proportion of difficult-to-recover reserves is larger and larger, and the low-permeability heavy oil reservoir becomes a development main layer gradually. However, compared with the common oil deposit exploitation, the low-permeability heavy oil deposit has the characteristics of low permeability, high viscosity, high density, high exploitation flow resistance and the like, and the exploitation difficulty is very high. For example, the thick oil comprises common thick oil and extra thick oil, the viscosity range of the thick oil in an oil reservoir is 50-50000 mPa.s, and the viscosity of the extra thick oil (such as tar sand) is more than 50000 mPa.s. Excessive viscosity results in excessive flow resistance of the thick oil, and lower permeability further increases the development difficulty of the thick oil.
Because the viscosity of the thickened oil is greatly affected by temperature, the thermal oil recovery technology becomes a main method for solving the problem that the high-viscosity thickened oil flows in a reservoir. The steam flooding technology is the most extensive and effective thermal oil extraction development means due to lower cost, simple technical operation and low risk.
The traditional steam injection thermal recovery technology has the following problems when the low-permeability heavy oil reservoir is applied:
(1) In the seepage process, the dryness of the steam is reduced along with the increase of the migration distance, so that the range of the heat wave of the steam is small, and the heat exchange efficiency is low.
(2) In the middle and later stages of development, with the increase of steam injection quantity, under the action of gravity differentiation, the phenomenon of steam overburden and the phenomenon of inter-layer or intra-layer channeling of steam occur.
(3) With further development, the oil saturation of the reservoir is reduced, and the steam injection consumption is huge, which is insufficient for economically and effectively developing the low-permeability thick oil reservoir.
In order to further improve the recovery degree of thickened oil, chinese patent CN115045643 discloses a carbon dioxide fracturing-huff and puff combined production method using a surfactant, wherein the method comprises the steps of fracturing carbon dioxide, huff and puff carbon dioxide, and combining a horizontal well and surfactant oil displacement. The fracturing mode of mixing carbon dioxide and chemical agents is utilized to reform the reservoir, so that a complex seam net can be constructed, the flow of crude oil is improved, and the problems of strong sensitivity, insufficient energy, quick decrease of oil well yield and the like of the hypotonic reservoir can be solved. After the surfactant slug is injected in front, the interfacial tension of oil and gas is effectively reduced, the wettability of the porous medium of the reservoir is changed, and the effect is maximized, so that the oil washing efficiency is increased, and the yield increasing effect is improved.
Although the patent uses the surfactant and the carbon dioxide to improve the exploitation of the low-permeability thick oil through the fracturing and huff-and-puff process, the production mode is huff-and-puff, namely only one well is used for injection, well-flushing and exploitation in the production process, the application range is limited, and the production method can only be used for reservoirs with small oil reservoir range and thin oil layer thickness.
Therefore, a thermal recovery method capable of improving the flowing capability and flowing distance of the hypotonic thickened oil in the stratum and enhancing the long-distance heat transfer capability of steam is needed to realize the purpose of efficiently recovering the thickened oil.
Disclosure of Invention
The invention provides a thermal recovery method for improving the recovery ratio of a low-permeability heavy oil reservoir, which aims at solving the problems that the heavy oil in the low-permeability heavy oil reservoir is difficult to flow, the steam heat action distance is short and the heat dissipation is fast.
The specific technical scheme is as follows:
a thermal recovery method for improving the recovery ratio of a low-permeability heavy oil reservoir comprises the following steps:
(1) Steam flooding injection stage: injecting steam into an injection well, wherein the steam injection temperature is more than or equal to 250 ℃, the steam injection dryness is more than or equal to 0.95, the steam injection speed is 1.5-3mL/min, and the steam injection pressure of the steam is 0.5-1MPa; and when the steam injection amount reaches 1-1.2PV, performing carbon dioxide and steam injection stages.
Steam injection tests show that the steam injection conditions are favorable for expanding the action range of steam heat to the greatest extent. When the steam injection speed is low, for example, the steam injection speed is 0.5-1mL/min, the steam sweep range is extremely low; when the steam injection speed is too high, for example, the steam injection speed is 5mL/min, the gas channeling occurs earlier. And (3) considering all factors, obtaining that the steam injection speed is 1.5-3mL/min, and promoting the steam to transfer heat to a long distance as far as possible on the premise of avoiding the premature occurrence of gas channeling.
Also, steam injection experiments show that low-pressure steam injection within the range of 0.5-1MPa is beneficial to improving the seepage distance of steam.
The inventor finds that when the steam injection amount reaches 1-1.2PV, the expansion of the steam cavity tends to be stable in the steam flooding injection stage, and the steam wave range is not expanded. At the moment, the carbon dioxide and steam injection stage is carried out, so that the expansion range of the steam cavity and the steam heat action distance can be effectively enlarged.
(2) Carbon dioxide and steam injection stage: after mixing carbon dioxide and steam, co-injecting the mixture into an injection well in a form of mixed gas, wherein the injection speed ratio of the carbon dioxide to the steam is 1:1; when the oil-gas ratio is more than 800m 3 At the time of/t, carrying out an oil displacement agent slug injection stage; production oil-gas ratio is more than 800m 3 At/t, severe gas channeling is considered.
Steam injection experiments show that carbon dioxide and steam are injected at an injection speed of 1:1, so that a hypertonic channel can be opened by taking carbon dioxide as steam, and serious gas channeling can not be caused.
(3) And (3) oil displacement agent slug injection stage: selecting a water-soluble oil displacement agent, and injecting an oil displacement agent slug into the stratum through an injection well; stopping the injection of the oil displacement agent when the injection quantity of the oil displacement agent reaches a set value; entering a carbon dioxide auxiliary steam flooding injection stage.
The oil displacement agent adopts the water-soluble oil displacement agent, and the water-soluble oil displacement agent reduces the viscosity of the thick oil by emulsifying the thick oil in the steam injection development process, improves the viscosity of the thick oil and promotes the flow of the thick oil; the pore generated after the heavy oil flows out provides a hypertonic channel for the subsequent carbon dioxide auxiliary steam flooding injection stage, so that steam seeps to the far end of an injection well, and the extraction degree of a low-permeability heavy oil reservoir is improved. Meanwhile, the early-stage injected steam can carry the water-soluble oil displacement agent to be conveyed to a far-end cold oil area, and condensed water formed by condensing the radiated steam can provide a required large water mixing amount for the water-soluble oil displacement agent to emulsify thick oil.
The conventional oil-soluble oil displacement agent in the prior art improves the viscosity of the thickened oil by reducing the surface tension of the liquid, changing the wettability mechanism and the like, can be used for improving the development effect of the thickened oil before steam injection, realizes the conventional cold recovery viscosity reduction production of the thickened oil well, and is suitable for oil wells with high heavy components such as asphalt. The invention aims at a hypotonic reservoir with less scale such as asphalt colloid, and the oil-soluble oil displacement agent is accumulated in the near-wellbore zone of an injection well after being injected, so that the steam and the carbon dioxide injected subsequently are prevented from flowing to the far end.
In the early stage, namely the carbon dioxide and steam injection stage, the carbon dioxide and the steam are injected together, so that the aim is to expand a hypertonic channel and carry steam seepage by virtue of low seepage resistance of the carbon dioxide. The carbon dioxide carries steam to realize long-distance heat transfer, after gas channeling occurs, gas injection is stopped, and the oil displacement agent slugs are injected, so that a gas channeling channel can be blocked, the uniform propulsion of the front edge of the steam is realized, the effect of high-temperature damage of the oil displacement agent on thick oil emulsification can be avoided, the residual oil on the side wall is more easily stripped, and the recovery ratio of the thick oil is further improved.
If the prior art chooses to inject the oil displacement agent in the early stage, the solvent will block the hypertonic channel after injection, and the purposes of promoting the steam to permeate to the far end, expanding the steam cavity and improving the steam heat wave and range can not be achieved. Meanwhile, the oil displacement agent and the steam are injected together, so that the problem that the components of the oil displacement agent are damaged by the high temperature of the steam can exist.
The water-soluble oil displacement agent which is commercially available and has high temperature resistance, mineralization resistance and surfactant can be used in the invention. Such as water-soluble ZK-005 type vapor flooding oil washes purchased from Qinghai-field, science and technology, inc.
(4) Carbon dioxide-assisted steam flooding injection stage: and (3) keeping the injection speed ratio of steam to carbon dioxide to be 1:1, and injecting steam and carbon dioxide in a synergistic way in a mixed gas mode until the water content of the produced liquid is higher than 98wt percent, and stopping production.
In the invention, the well pattern of the low-permeability heavy oil reservoir block in the method for improving the recovery ratio of the low-permeability heavy oil reservoir is in a one-injection multi-production mode. I.e., multiple production wells of one injection well, in a manner different from the single well injection production well configuration of steam huff and puff technology.
Furthermore, the one-injection multi-production mode is one-injection four-production mode, and a well arrangement mode of central well injection and four-corner well production is adopted. The pattern is closely related to the steam injection rate. Of course, in the practical application process, the method of the invention can also adopt well-arrangement modes such as a reverse nine-point method (three injection and one production), a seven-point method (two injection and one production) and the like.
In the invention, the mining ratio of the low-permeability heavy oil reservoir block flooding well pattern in the low-permeability heavy oil reservoir mining method is more than 1.2.
In the invention, the injection speed of steam and carbon dioxide in the step (2) and the step (4) of the method for improving the recovery ratio of the low-permeability heavy oil reservoir is controlled to be 5000-10000 m 3 /d。
In the invention, the concentration of the water-soluble oil displacement agent in the step (3) of the method for improving the recovery ratio of the low-permeability heavy oil reservoir is 0.3-0.5wt%.
In the invention, the set value of the injection amount of the oil displacement agent in the step (3) of the method for improving the recovery ratio of the low-permeability heavy oil reservoir is 0.1-0.2PV. If the injection amount of the oil displacement agent exceeds 0.2PV, an oversized oil displacement agent slug will block the steam seepage channel.
The application of the method for improving the recovery ratio of the low-permeability heavy oil reservoir in developing the oil reservoir meeting at least the following conditions:
the average permeability of the oil reservoir is less than 1000mD;
the effective porosity of the oil reservoir is 35-40%;
the saturation of initial oil content is more than 86%;
the formation temperature is 50-80 ℃;
the stratum inclination angle is 1-2 degrees;
the burial depth of the oil layer is more than 1000m;
the thickness of the oil layer is less than 10m;
the density of crude oil is more than or equal to 0.935g/cm 3 The viscosity of crude oil is more than or equal to 10000 mPa.s;
the mineralization degree of the stratum water is 9000-12000 mg/L.
The thermal recovery method aims at solving the problem that the traditional steam injection technology cannot effectively develop the special reservoir with poor physical properties such as a thin oil layer, high mineralization degree, low oil saturation degree and the like. The method of the invention can improve the recovery ratio of the low permeability heavy oil reservoir with severe conditions, and is naturally applicable to the conventional reservoir conditions which can be acted by the conventional steam flooding, therefore, compared with the conventional steam flooding, the thermal recovery method of the invention widens the application range and improves the steam flooding development effect.
The beneficial effects of the invention are as follows: the invention adopts carbon dioxide and an oil displacement agent to assist steam flooding, reduces the viscosity of the thickened oil by emulsifying the thickened oil, and increases the fluidity of the thickened oil. The thick oil can provide a high-permeability channel for steam after flowing out, so that injected steam is transmitted to the far end and heated to the thick oil at a position far away from the injection well, thereby improving the thermal utilization range of the thick oil and increasing the recovery ratio of the thick oil. And the energy of the stratum is further supplemented by the action of expanding crude oil by the carbon dioxide.
The setting sequence of the thermal recovery method is as follows: steam flooding, carbon dioxide+steam flooding, oil displacement agent, carbon dioxide+steam flooding, and the like, and have larger limitations if other sequential injection is adopted. For example, if carbon dioxide is injected in conjunction with steam flooding at an early stage, steam breaks through at the early stage of injection, resulting in little heavy oil usage. If the oil displacement agent is injected in the initial stage, the solvent can not block the hypertonic channel after being injected, so that the aims of promoting the steam to permeate towards the far end, expanding the steam cavity and improving the steam heat wave and range can not be achieved.
According to the invention, long-distance heat transfer is realized by carrying steam with carbon dioxide, and an oil displacement agent is assisted, so that not only is the fluidity of the thickened oil improved, but also the heterogeneity is improved by plugging a hypertonic channel, and the front edge of the steam is uniformly pushed, so that the invention can be used for various low-permeability thickened oil reservoirs with different oil-containing areas, different reservoir buries and different heterogeneities.
The carbon dioxide and the oil displacement agent cooperate to assist the steam flooding technology, so that steam heat energy can be promoted to be used for improving the fluidity of thick oil, the thermal application range can be expanded by at least 20.7%, the temperature of the far end of a model can be increased by at least 11.9%, and the thick oil at the far end of an injection well of a low-permeability reservoir can be effectively extracted. The method can improve the recovery ratio of the thick oil thermal recovery to 51.5%, and improve the development effect of the low-permeability thick oil reservoir.
Drawings
FIG. 1 is a schematic diagram of an experimental flow apparatus for performing a thermal recovery method simulation experiment according to the present invention in example 1;
wherein 1 is an ISCO piston pump, 2 is a deionized water intermediate container, 3 is a steam generator, 4 is a carbon dioxide intermediate container, 5 is a gas flowmeter, 6 is a one-way valve, 7 is a six-way valve, 8 is a three-dimensional model, 9 is a constant temperature box, 10 is a temperature and pressure acquisition device, 11 is a water intermediate container, 12 is a thickened oil intermediate container, 13 is an oil displacement agent intermediate container, 14 is a gas-liquid separator, and 15 is a beaker.
FIG. 2 is a graph comparing the recovery ratio of the thermal recovery method described in example 1 with that of a conventional steam flooding.
FIG. 3 is a graph showing the comparison of the thermal recovery method described in example 1 and the model temperature profile of a conventional steam flooding.
Fig. 4 is a graph showing statistical comparison between recovery ratio and maximum oil recovery speed of carbon dioxide and oil displacement agent assisted steam flooding and conventional steam flooding, oil displacement agent+carbon dioxide flooding, oil displacement agent+steam flooding in different injection modes as described in example 1.
Fig. 5 is a graph showing the comparison of the long-distance heat transfer results of steam at different injection speeds in the steam flooding injection stage in the thermal recovery method according to the present invention.
Fig. 6 is a graph comparing temperature measurement results under different steam injection pressures at the steam flooding injection stage in the thermal recovery method according to the present invention.
FIG. 7 is a graph showing the comparison of temperature measurement results at different injection speed ratios of carbon dioxide and steam in the thermal recovery method according to the present invention.
FIG. 8 is a graph showing the particle size distribution of an emulsion at an oil displacement agent concentration of 0.1wt% in the injection stage of an oil displacement agent slug in a thermal recovery method according to the present invention.
FIG. 9 is a graph showing the particle size distribution of an emulsion at an oil displacement agent concentration of 0.3wt% in the injection stage of an oil displacement agent slug in a thermal recovery method according to the present invention.
FIG. 10 is a graph showing the particle size distribution of an emulsion at an oil displacement agent concentration of 0.5wt% in the injection stage of an oil displacement agent slug in a thermal recovery method according to the present invention.
FIG. 11 is a graph comparing oil recovery effect to different oil displacement agent slug volumes in the oil displacement agent slug injection stage of the thermal recovery method of the present invention.
FIG. 12 is a graph showing the temperature distribution of comparative example 1 in which carbon dioxide and steam are injected in different modes.
Detailed Description
The present invention will be described in detail with reference to examples and drawings, but is not limited thereto.
1. In the specific embodiment, the device model is as follows: the steam generator is GL-1 type; the gas flowmeter is of the type D07-11C.
2. Reagent: the oil displacement agent is water-soluble ZK-005 type oil washing agent for steam flooding, and is purchased from Qingdian middling plant science and technology Co.
Example 1
The thermal recovery method disclosed by the invention is simulated by adopting an experimental flow device shown in fig. 1. The simulated actual low permeability heavy oil reservoir environmental conditions are: the oil reservoir permeability is 850mD; the effective porosity of the oil reservoir is 37%; the initial oil saturation was 86.5%; the formation temperature was 65 ℃; the dip angle of the oil reservoir stratum is 1 degree; the oil deposit burial depth is 1120m; the thickness of the oil layer is 8.9m; crude oil density of 0.935g/cm 3 The viscosity of crude oil at reservoir temperature is 14800 mpa.s; reservoir stratum water mineralization degree of 10000mg/L。
The specific operation steps are as follows:
(1) Preparing a three-dimensional model: in laboratory conditions, the reservoir prototype parameters are transformed by applying a similarity criterion to obtain a set of model control parameters, and a physical model similar to the prototype is designed and built on the basis. The three-dimensional sand filling experimental equipment is utilized to meet the requirements of the thermal recovery method of the invention on the low-permeability heavy oil reservoir:
(2) Model filling: the three-dimensional model 8 has the dimensions of 400mm multiplied by 150mm, three layers of 36 temperature sensors and 3 pressure sensors are uniformly distributed in the upper, middle and lower directions, and the temperature sensors and the pressure sensors are connected with the temperature and pressure acquisition device 10; the injection well is positioned at the center of the model, and the four corner wells are extraction wells. The simulated thickened oil density is 0.935g/cm 3 A reservoir temperature viscosity of 14800 mPa-s; the model was evacuated, saturated water (from water intermediate vessel 11), saturated oil (from thick oil intermediate vessel 12), calculated to have a model permeability of 850mD, porosity of 37%, and initial oil saturation of 86.5%, based on which the actual hypotonic thick oil reservoir environment was simulated.
(3) Experiment preparation: the external incubator 9 was opened to preheat the three-dimensional model 8 to 65 ℃ in advance, the ISCO piston pump 1, the deionized water intermediate vessel 2 and the steam generator 3 were opened, the outlet temperature of the steam generator 3 was set to 250 ℃, and after the temperatures of the steam generator 3 and the incubator 9 were all stabilized, the experiment was started.
(4) Steam flooding injection stage: the steam injection temperature is 250 ℃, the steam injection dryness is 0.95, the steam injection pressure of the steam is 0.5MPa, and the steam injection speed is 2 mL-min -1 (equivalent water) when the steam injection amount reaches 1.2PV, the phase is changed into carbon dioxide and steam injection.
(5) Carbon dioxide and steam injection stage: the carbon dioxide intermediate container 4 is filled with carbon dioxide having a purity of 99.9%, and the carbon dioxide intermediate container 4 is connected to the steam generator 3 through a six-way valve 7. The carbon dioxide in the carbon dioxide intermediate container 4 is mixed with the steam generated by the steam generator 3 through the gas flowmeter 5 and the one-way valve 6 and then is cooperated in the form of mixed gasInjecting into the three-dimensional model 8, wherein the carbon dioxide injection speed is 8000m 3 /d; and the injection speed ratio of carbon dioxide to steam is 1:1, when the production oil gas ratio is more than 800m 3 And at/t, the injection stage is changed into an oil displacement agent slug injection stage when serious gas channeling occurs.
(6) And (3) oil displacement agent slug injection stage: the oil displacement agent intermediate container 13 is internally provided with an oil displacement agent water-soluble ZK-005 type oil washing agent for steam flooding, the injection concentration of the oil displacement agent is 0.5wt percent, and the injection amount is 0.1PV; stopping the injection of the oil displacement agent when the set value reaches 0.1PV; converting into a carbon dioxide auxiliary steam flooding injection stage;
(7) Carbon dioxide-assisted steam flooding injection stage: the steam and carbon dioxide are injected cooperatively in a mixed gas form until the water content of the produced liquid collected in the beaker 15 after passing through the gas-liquid separator 14 is higher than 98wt% by keeping the injection speed ratio of the steam and the carbon dioxide at 1:1, and the simulation is stopped.
And (3) carrying out oil-water separation and metering on the obtained produced liquid, wherein the final recovery statistical result is shown in figure 2.
Compared with the traditional steam flooding injection, the carbon dioxide and oil displacement agent auxiliary steam flooding injection of the embodiment 1 improves the recovery ratio of the low-permeability thick oil by 4.01%, improves the thermal utilization range of the thick oil, and has obvious yield-increasing effect on crude oil.
The model temperature profile of carbon dioxide and displacement agent assisted vapor flooding injection, conventional vapor flooding injection of example 1 is shown in fig. 3.
As can be seen from fig. 3, the temperatures of the five temperature measuring points of the conventional steam flooding are 135.1 ℃, 114.8 ℃, 94.5 ℃, 82.0 ℃ and 78.5 ℃ respectively; example 1 the temperature of the five temperature measurement points of the carbon dioxide and oil displacement agent auxiliary steam flooding were 129.8 ℃, 117.3 ℃, 109.2 ℃, 100.5 ℃ and 87.8 ℃ respectively. As can be seen from comparison of test results, the thermal recovery method described in example 1 expands the thermal utilization range by 20.7% and increases the temperature of the distal end of the model by 11.9%.
The carbon dioxide and oil-displacing agent assisted steam flooding described in example 1 was compared with conventional steam flooding, oil-displacing agent+carbon dioxide flooding, oil-displacing agent+steam flooding injection, and recovery ratio and maximum oil recovery rate statistics under different injection are shown in fig. 4.
As can be seen from fig. 4, the recovery ratio of the carbon dioxide and oil displacement agent assisted vapor flooding technique of example 1 has the best recovery ratio improvement effect and the highest maximum oil recovery speed. If the oil displacement agent and the carbon dioxide are injected together, the oil displacement effect is worst under the condition of no steam heat, the thickened oil hardly moves, and the recovery ratio is only 47.1%; if the oil displacement agent and the steam flooding are adopted for injection, the recovery ratio is improved to a certain extent compared with that of single steam flooding under the action of the oil displacement agent, but the maximum oil extraction speed is only increased from 3.0g/mL to 3.3g/mL, so that the driving force is insufficient and the steam seepage is blocked. When the carbon dioxide and the oil displacement agent assist in steam flooding, the fluidity of the thickened oil is improved, the steam seepage capability is improved, the seepage speed of the mixed fluid is increased, and the driving force is increased, so that more thickened oil is driven out, and the recovery ratio and the oil recovery speed are obviously improved.
Example 2
The purpose of this example is to examine the effect of the steam injection rate in the steam flooding injection stage on the range of action of steam heat.
The procedure described in example 1 was followed, except that: the steam injection speeds of the steam flooding injection stage were set to 0.5mL/min, 1mL/min, 1.5mL/min, 3mL/min, and 5mL/min, respectively. Otherwise, the same as in example 1 was conducted.
The results of the long-distance heat transfer of the steam at different injection speeds are shown in FIG. 5, wherein the temperature measuring points are 15cm, 20cm, 25cm, 30cm, 35cm and 40cm away from the steam injection well.
As shown in connection with FIG. 5, the steam sweep range is very low when the steam injection rate is low in the range of 0.5-1 mL/min. When the steam injection speed reaches 5mL/min too high, the gas channeling occurs earlier, and the steam injection speed is preferably in the range of 1.5-3mL/min.
The above speed range can promote the steam to transfer heat to a long distance as far as possible under the condition of avoiding the premature gas channeling.
Example 3
The purpose of this example is to examine the effect of the steam injection pressure of the steam on the range of action of the steam heat in the steam flooding stage.
The procedure described in example 1 was followed, except that: the steam injection pressure of the steam flooding injection stage is respectively set to be 0.5MPa, 1MPa, 2MPa, 3MPa and 4MPa. Otherwise, the same as in example 1 was conducted.
The results of the temperature measurements at different steam injection pressures are shown in fig. 6.
As can be seen from fig. 6, as the steam injection pressure decreases from 4MPa to 0.5MPa, the temperature at the position of the temperature measurement point 5 increases from 100.6 ℃ to 162.1 ℃, which proves that as the steam injection pressure decreases, the seepage distance of steam is increased, more steam seeps to the position of the temperature measurement point 5 far from the steam injection well, i.e. low-pressure steam injection is beneficial to increasing the steam seepage distance, and finally the steam injection pressure is screened out to be 0.5-1MPa.
Example 4
The purpose of this example was to examine the effect of different injection rate ratios of carbon dioxide to steam and carbon dioxide in the steam injection stage.
The procedure described in example 1 was followed, except that: the injection rate ratio of carbon dioxide to steam and carbon dioxide in the steam injection stage was set to 1:1, 1:2, 1:3, respectively. Otherwise, the same as in example 1 was conducted.
The results of temperature measurements at different injection rate ratios are shown in fig. 7.
As shown in fig. 7, as the ratio of the injection speed increases, the proportion of carbon dioxide in the mixed fluid increases, and the proportion of steam decreases, so that the temperature at the injection end (at the temperature measuring point 1) continues to decrease. When the injection speed is relatively high (1:2 or 1:3), gas channeling is easy to occur, and the steam injected subsequently flows out along the gas channeling channel after insufficient heat transfer, so that the temperature of each temperature measuring point is continuously reduced. Therefore, the ratio of the injection speed is 1:1, and under the injection speed, the hypertonic channel can be opened by taking carbon dioxide as steam, and serious gas channeling can not be caused.
Example 5
The purpose of this example is to examine the effect of different concentrations of the oil-displacing agent on the emulsification of the thickened oil in the injection stage of the oil-displacing agent slugs.
The procedure described in example 1 was followed, except that: the concentration of the oil displacement agent in the oil displacement agent slug injection stage is respectively set to be 0.1wt%, 0.3wt% and 0.5wt%. Otherwise, the same as in example 1 was conducted.
As is clear from comparison of fig. 8, 9 and 10, as the concentration of the oil-displacing agent increases, the emulsifying effect on the thickened oil becomes stronger, the peak value of the particle size distribution of the W/O emulsion shifts to the left, and the particle size of the dispersed phase oil droplets gradually decreases. The smaller oil drop particle size is more favorable for stripping and extracting oil drops, and the recovery ratio is higher. However, the larger concentration of the oil displacement agent also means larger oil displacement cost, so that the concentration of the oil displacement agent is finally determined to be 0.3-0.5wt% by combining the concentration of the oil displacement agent commonly used in the oilfield site and experimental results.
Example 6
The purpose of this example is to examine the effect of different displacement agent slug volumes on oil recovery in the displacement agent slug injection stage.
The procedure described in example 1 was followed, except that: the injection quantity set values of the oil displacement agent in the injection stage of the oil displacement agent slug are respectively 0.1PV, 0.2PV and 0.3PV. Otherwise, the same as in example 1 was conducted.
As shown in fig. 11, the thick oil emulsification effect became better and the recovery increased gradually as the slug volume increased, but when the displacement agent injection slug volume increased from 0.1PV to 0.2PV, the recovery increased by 2.37%, and when the slug volume increased from 0.2PV to 0.3PV, the recovery increased by only 1.28%. Considering that the development cost is increased along with the increase of the injection quantity of the oil displacement agent, the injection quantity of the oil displacement agent slug is finally set to be 0.1-0.2PV, so that the thickened oil is developed economically and efficiently.
Comparative example 1
The present comparative example differs from example 1 in that the carbon dioxide and steam injection stage and the carbon dioxide-assisted steam flooding injection stage are both: carbon dioxide is injected alternately with steam. Otherwise, the same as in example 1 was conducted.
The obtained temperature distribution diagram is shown in FIG. 12.
As can be seen from fig. 12, the co-mixed injection of carbon dioxide and steam allows a certain decrease in the injection end temperature, but the temperature at the far end of the model is significantly increased, compared with the alternative injection mode of carbon dioxide and steam and the pure steam flooding injection mode. For a low-permeability heavy oil reservoir, how to promote the steam seepage is far, and how to promote the far-end cold oil region to be subjected to the heat wave of steam and to be the key for improving the fluidity of the heavy oil is that the mode of synergistic mixing injection of carbon dioxide and steam is more beneficial to exploitation of the low-permeability heavy oil reservoir.

Claims (8)

1. The thermal recovery method for improving the recovery ratio of the low-permeability heavy oil reservoir is characterized by comprising the following steps of:
(1) Steam flooding injection stage: injecting steam into an injection well, wherein the steam injection temperature is more than or equal to 250 ℃, the steam injection dryness is more than or equal to 0.95, the steam injection speed is 1.5-3mL/min, and the steam injection pressure of the steam is 0.5-1MPa; when the steam injection amount reaches 1-1.2PV, carbon dioxide and steam injection stages are carried out;
(2) Carbon dioxide and steam injection stage: after mixing carbon dioxide and steam, co-injecting the mixture into an injection well in a form of mixed gas, wherein the injection speed ratio of the carbon dioxide to the steam is 1:1; when the oil-gas ratio is more than 800m 3 At the time of/t, carrying out an oil displacement agent slug injection stage;
(3) And (3) oil displacement agent slug injection stage: the oil displacement agent is water-soluble, and the oil displacement agent slug is injected into the stratum through the injection well; stopping the injection of the oil displacement agent when the injection quantity of the oil displacement agent reaches a set value; entering a carbon dioxide auxiliary steam flooding injection stage;
(4) Carbon dioxide-assisted steam flooding injection stage: and (3) keeping the injection speed ratio of steam to carbon dioxide to be 1:1, and injecting steam and carbon dioxide in a synergistic way in a mixed gas mode until the water content of the produced liquid is higher than 98wt percent, and stopping production.
2. The thermal recovery method for enhanced oil recovery of a hypotonic heavy oil reservoir of claim 1, wherein the pattern of injection wells of the hypotonic heavy oil reservoir block is a one-injection-multiple-production pattern.
3. The thermal recovery method for enhanced recovery of a hypotonic heavy oil reservoir of claim 2, wherein the one-injection-multiple-production mode is one-injection-four-production.
4. The thermal recovery method for enhanced recovery of a hypotonic heavy oil reservoir of claim 1, wherein the low hypotonic heavy oil reservoir block injection well pattern has a mining ratio of > 1.2.
5. The thermal recovery method for improving the recovery ratio of a hypotonic heavy oil reservoir according to claim 1, wherein the injection speeds of steam and carbon dioxide in the step (2) and the step (4) are controlled to be 5000-10000 m 3 /d。
6. The thermal recovery method for enhancing the recovery of a hypotonic heavy oil reservoir according to claim 1, wherein the concentration of the water-soluble oil displacement agent in the step (3) is 0.3-0.5wt%.
7. The thermal recovery method for improving the recovery ratio of the low-permeability heavy oil reservoir according to claim 1, wherein the injection amount of the oil displacement agent in the step (3) is set to be 0.1-0.2PV.
8. Use of a thermal recovery method for enhanced recovery of a hypotonic heavy oil reservoir according to any one of claims 1-7 for developing a reservoir meeting at least the following conditions:
the average permeability of the oil reservoir is less than 1000mD;
the effective porosity of the oil reservoir is 35-40%;
the saturation of initial oil content is more than 86%;
the formation temperature is 50-80 ℃;
the stratum inclination angle is 1-2 degrees;
the burial depth of the oil layer is more than 1000m;
the thickness of the oil layer is less than 10m;
the density of crude oil is more than or equal to 0.935g/cm 3 The viscosity of crude oil is more than or equal to 10000 mPa.s;
the mineralization degree of the stratum water is 9000-12000 mg/L.
CN202310353139.3A 2023-04-04 2023-04-04 Thermal recovery method for improving recovery ratio of low-permeability heavy oil reservoir Active CN116066045B (en)

Priority Applications (1)

Application Number Priority Date Filing Date Title
CN202310353139.3A CN116066045B (en) 2023-04-04 2023-04-04 Thermal recovery method for improving recovery ratio of low-permeability heavy oil reservoir

Applications Claiming Priority (1)

Application Number Priority Date Filing Date Title
CN202310353139.3A CN116066045B (en) 2023-04-04 2023-04-04 Thermal recovery method for improving recovery ratio of low-permeability heavy oil reservoir

Publications (2)

Publication Number Publication Date
CN116066045A true CN116066045A (en) 2023-05-05
CN116066045B CN116066045B (en) 2023-06-02

Family

ID=86175347

Family Applications (1)

Application Number Title Priority Date Filing Date
CN202310353139.3A Active CN116066045B (en) 2023-04-04 2023-04-04 Thermal recovery method for improving recovery ratio of low-permeability heavy oil reservoir

Country Status (1)

Country Link
CN (1) CN116066045B (en)

Citations (8)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US4127172A (en) * 1977-09-28 1978-11-28 Texaco Exploration Canada Ltd. Viscous oil recovery method
US4640357A (en) * 1985-09-11 1987-02-03 Mobil Oil Corporation Multistep method for viscous hydrocarbon recovery
US5295540A (en) * 1992-11-16 1994-03-22 Mobil Oil Corporation Foam mixture for steam and carbon dioxide drive oil recovery method
CN101139923A (en) * 2007-10-17 2008-03-12 中国石油天然气股份有限公司 Method for developing deep-layer heavy crude reservoir by carbon dioxide auxiliary steam driving
CN103573231A (en) * 2012-07-23 2014-02-12 中国石油化工股份有限公司 Method for improving recovery ratio of sensitive heavy oil reservoir
CN105587301A (en) * 2014-10-23 2016-05-18 中国石油化工股份有限公司 Method capable of improving recovery efficiency through heavy oil thermal recovery
CN105952425A (en) * 2016-07-11 2016-09-21 中国石油大学(华东) Method for improving ordinary heavy oil reservoir recovery ratio by adopting chemical agents to assist CO2 huff and puff
CN115045643A (en) * 2022-07-11 2022-09-13 中国石油大学(华东) Carbon dioxide fracturing-huff and puff combined production method applying surfactant

Patent Citations (8)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US4127172A (en) * 1977-09-28 1978-11-28 Texaco Exploration Canada Ltd. Viscous oil recovery method
US4640357A (en) * 1985-09-11 1987-02-03 Mobil Oil Corporation Multistep method for viscous hydrocarbon recovery
US5295540A (en) * 1992-11-16 1994-03-22 Mobil Oil Corporation Foam mixture for steam and carbon dioxide drive oil recovery method
CN101139923A (en) * 2007-10-17 2008-03-12 中国石油天然气股份有限公司 Method for developing deep-layer heavy crude reservoir by carbon dioxide auxiliary steam driving
CN103573231A (en) * 2012-07-23 2014-02-12 中国石油化工股份有限公司 Method for improving recovery ratio of sensitive heavy oil reservoir
CN105587301A (en) * 2014-10-23 2016-05-18 中国石油化工股份有限公司 Method capable of improving recovery efficiency through heavy oil thermal recovery
CN105952425A (en) * 2016-07-11 2016-09-21 中国石油大学(华东) Method for improving ordinary heavy oil reservoir recovery ratio by adopting chemical agents to assist CO2 huff and puff
CN115045643A (en) * 2022-07-11 2022-09-13 中国石油大学(华东) Carbon dioxide fracturing-huff and puff combined production method applying surfactant

Non-Patent Citations (1)

* Cited by examiner, † Cited by third party
Title
陶磊;刘雅莉;林吉生;李兆敏;何岩峰: "温度与表面活性剂协同作用下的特超稠油油水固界面行为分析", 科学技术与工程/温度与表面活性剂协同作用下的特超稠油油水固界面行为分析, no. 14, pages 152 *

Also Published As

Publication number Publication date
CN116066045B (en) 2023-06-02

Similar Documents

Publication Publication Date Title
Xu et al. A review of development methods and EOR technologies for carbonate reservoirs
Kumar et al. A comprehensive review on chemically enhanced water alternating gas/CO2 (CEWAG) injection for enhanced oil recovery
Guillen et al. Pore scale and macroscopic displacement mechanisms in emulsion flooding
Altunina et al. Improved oil recovery of high-viscosity oil pools with physicochemical methods and thermal-steam treatments
Xu et al. An experimental study of combined foam/surfactant polymer (SP) flooding for carbone dioxide-enhanced oil recovery (CO2-EOR)
Ding et al. A comparative study of the mechanism and performance of surfactant-and alkali-polymer flooding in heavy-oil recovery
CN108131122B (en) Method for improving CO2 sequestration and crude oil recovery
CN104594859B (en) A kind of method of the fine and close oily oil reservoir of nano-fluid exploitation
WO2019223346A1 (en) Nitrogen composite huff-puff method for closed fault block oil reservoir
CA1195606A (en) In situ recovery process for heavy oil sands
Pillai et al. Applications of microemulsions in enhanced oil recovery
CN109113700A (en) A kind of method of heavy crude reservoir old area multimedium steam oil production
Korolev et al. Regulation of filtration characteristics of highly watered terrigenous formations using complex chemical compositions based on surfactants
CN103321621A (en) Heavy oil displacement method using wedged vicious slug
CN110552671A (en) Method for realizing high-efficiency development of heavy oil reservoir by utilizing dimethyl ether to assist CO 2 flooding
Wang et al. In-situ CO2 generation huff-n-puff for enhanced oil recovery: Laboratory experiments and numerical simulations
US4161217A (en) Hot water foam oil production process
Junjian et al. Mechanisms of water block removal by surfactant micellar solutions in low permeability reservoirs
CN116066045B (en) Thermal recovery method for improving recovery ratio of low-permeability heavy oil reservoir
Rojas et al. Scaled model studies of carbon dioxide/brine injection strategies for heavy oil recovery from thin formations
Zhao et al. Performance improvement of CO2 flooding using production controls in 3D areal heterogeneous models: Experimental and numerical simulations
CN103982166B (en) Supercritical carbon dioxide foam profile device and transfer drive method
CN107558975B (en) Method for improving later development of steam assisted gravity drainage by using viscosity reducer
Rezaei et al. Pressure evolution and production performance of waterflooding in n-heptane-saturated fired berea cores
Neogi Oil Recovery and Microemulsions

Legal Events

Date Code Title Description
PB01 Publication
PB01 Publication
SE01 Entry into force of request for substantive examination
SE01 Entry into force of request for substantive examination
GR01 Patent grant
GR01 Patent grant