Oil extraction method for low-permeability reservoir

Abstract

The invention relates to an oil extraction method for a low-permeability reservoir, and belongs to the technical field of oil extraction. According to the oil extraction method for the low-permeability reservoir, the pressure reduction auxiliary, the carbon dioxide and the water are sequentially injected into the reservoir stratum in a slug mode, the pressure reduction auxiliary can promote the carbon dioxide to extract light components of the crude oil, a rich gas phase is formed in a leading edge zone of the crude oil, and the miscible phase pressure of the carbon dioxide and the crude oil is reduced. The water slug can increase the formation pressure to the optimal miscible pressure value, and can transform the reservoir to form micro-cracks, increase seepage channels and enlarge the swept volume of carbon dioxide. In addition, water has a certain imbibition effect in the micro-crack transformation process, and remaining oil in the micro-pore throat can be effectively displaced; and the water slug can form a water-gas slug with gas in cracks and heterogeneous large pore channels, a certain flow control effect is achieved, during oil well open flow, the Jamin effect can slow down rapid escape of carbon dioxide, the pressure drop amplitude of a wellhead is slowed down, and then the oil change rate is increased.

Description

Technical Field

[0001] The invention relates to an oil production method for a low-permeability oil reservoir, belonging to the technical field of oil production. Background Art

[0002] Carbon dioxide huff and puff is an important method to improve the recovery rate of a single well and a single block of oil reservoirs, especially for low-permeability tight oil reservoirs, scattered fault block oil reservoirs, and depleted oil reservoirs. Carbon dioxide huff and puff is an important technology to improve crude oil recovery. The carbon dioxide injected into the formation will dissolve in the crude oil to expand the volume of the crude oil, which can effectively replenish the energy of the formation, extract the light hydrocarbon components in the crude oil, reduce the oil-water interfacial tension and crude oil viscosity, improve the mobility ratio, and expand the swept volume. In addition, carbon dioxide can dissolve in water, which will increase the viscosity of water, thereby reducing the mobility of water and making the water weakly acidic. To a certain extent, it can relieve the blockage and pollution of the seepage channel in the near-well area, thereby improving the reservoir development effect and further improving the recovery rate of the oil field.

[0003] However, the current carbon dioxide huff-and-puff technology has the following problems in its application: single well and single block oil reservoirs have been depleted and exploited, with a high degree of recovery and serious formation depletion. When the current formation pressure is lower than the minimum miscibility pressure, it is difficult for a small amount of carbon dioxide to form a uniform miscibility with crude oil; there is less residual oil in the near-well area of ​​low-permeability oil reservoirs, and the fluid flow conditions in the distal formation are poor. There is a lot of remaining oil but it is difficult to mobilize, so the injected carbon dioxide is difficult to be transferred to the distal well area, and the range of carbon dioxide huff-and-puff is small; secondly, when a single gas medium is huffed and puffed, cross-flow is easily formed in the heterogeneous reservoir, resulting in low oil recovery efficiency. Summary of the invention

[0004] The object of the present invention is to provide an oil recovery method for low permeability oil reservoirs, which can solve the problem of low oil recovery efficiency when the current carbon dioxide huff-and-puff process is used in low permeability oil reservoirs.

[0005] In order to achieve the above objectives, the technical solution adopted by the oil recovery method of the low permeability oil reservoir of the present invention is:

[0006] A method for producing oil from a low-permeability reservoir comprises the following steps: respectively and sequentially injecting a pressure-reducing auxiliary agent and liquid carbon dioxide into a target reservoir formation in the form of a segment plug, then injecting water into the formation until the average formation pressure reaches a micro-fracture pressure, reducing the water injection rate, continuing to inject water until the average formation pressure is greater than the original formation pressure and reaches an optimal miscibility pressure, stopping water injection, and then shutting the well and producing; the pressure-reducing auxiliary agent is selected from one or any combination of pentane, hexane, and an oil-soluble surfactant; the micro-fracture pressure is 0.8 to 0.95 of the formation fracture pressure, and the optimal miscibility pressure is equal to 1.1 to 1.3 times the minimum miscibility pressure of the formation crude oil and CO2.

[0007] The oil recovery method of the low permeability oil reservoir of the present invention is to inject a pressure reducing agent, carbon dioxide, and water into the oil reservoir formation in the form of a segment plug in sequence, wherein the pressure reducing agent can promote the extraction of light components of crude oil by carbon dioxide, form a gas-rich phase in the crude oil front zone, and reduce the miscible pressure of carbon dioxide and crude oil. The water segment plug can increase the formation pressure to the optimal miscible pressure value, and can transform the reservoir to form microcracks, increase the seepage channel, and push the carbon dioxide segment plug into the deep residual oil-rich zone to expand the carbon dioxide swept volume. In addition, water has a certain imbibition effect in the process of microcrack transformation, which can effectively displace the residual oil in the tiny pore throats; and the water segment plug can form a water-gas segment plug with gas in the cracks and heterogeneous large pores, which plays a certain flow control role. When the oil well is blown out, the Jamin effect can slow down the rapid escape of carbon dioxide, and the pressure drop at the wellhead is slowed down, thereby improving the oil change rate. And the use of water segment plugs can also reduce the amount of carbon dioxide and improve the economic benefits of carbon dioxide throughput.

[0008] In the present invention, the schematic diagram of the result after the pressure reducing agent, carbon dioxide and water are injected into the formation is as follows: Figure 1 The schematic diagram of the mechanism of micro-fracturing the formation when injecting water is shown in Figure 2 The schematic diagram of the mechanism of gas-water fluidity controlling the Jiamin effect is shown in Figure 3 shown.

[0009] The minimum miscibility pressure of formation crude oil and CO2 refers to the minimum miscibility pressure of carbon dioxide miscible flooding when the interfacial tension between the oil and gas phases is zero under a certain pressure and temperature. The minimum miscibility pressure of formation crude oil and CO2 can be tested according to the method specified in the standard SY / T6573-2003 "Minimum miscibility pressure capillary test method", and the pressure corresponding to the inflection point in the crude oil recovery curve obtained through a series of displacement experiments (i.e., the minimum miscibility pressure) can be obtained.

[0010] It is understood that the isomers of pentane or hexane are all suitable for the present invention. For example, the pentane is n-pentane, isopentane, and neopentane; the hexane is n-hexane, 2-methylpentane, 3-methylpentane, 2,3-dimethylbutane, and 2,2-dimethylbutane.

[0011] Preferably, the injection amount of the pressure reducing agent is 0.01-0.05 PV. The beneficial effect of the injection amount of the pressure reducing agent being 0.01-0.05 PV is that the mixed phase pressure can be reduced by 10-15%.

[0012] Preferably, the injection amount of the liquid carbon dioxide is 0.05-0.2 PV. The beneficial effect of the injection amount of the liquid carbon dioxide being 0.05-0.2 PV is to supplement the formation energy and form a miscible drive with the crude oil.

[0013] Preferably, the injection rate of the pressure reducing agent is 20-30 t / d. The beneficial effects of the pressure reducing agent injection rate of 20-30 t / d are: uniformly miscible with the front formation crude oil, forming a uniform miscible front zone, and expanding the affected range.

[0014] Preferably, the injection rate of the liquid carbon dioxide is 20-30 t / d. The beneficial effect of the injection rate of the liquid carbon dioxide being 20-30 t / d is to uniformly replenish the formation and expand the affected area.

[0015] Preferably, the water injection speed is 100-300 m 3 / d. Use 100~300m 3 The water injection rate of / d can quickly replenish the formation energy through the water plug and significantly increase the formation pressure to the optimal miscible pressure value; at the same time, the high-speed and high-pressure injection of the water plug can transform the reservoir, form micro-cracks, increase seepage channels, and push the carbon dioxide plug into the deep residual oil-rich zone, thereby expanding the carbon dioxide swept volume.

[0016] Preferably, the soaking time is equal to the sum of the pressure drop equilibrium time and the water imbibition equilibrium time; the pressure drop equilibrium time is the time required for the wellhead pressure to reach equilibrium during the on-site soaking process.

[0017] It is understandable that during the on-site well soaking implementation, the wellhead pressure will change with time. When the wellhead pressure is stable, the time difference between the start time of well soaking and the time when the wellhead pressure is stable is the pressure drop equilibrium time.

[0018] In the present invention, the water imbibition equilibrium time is obtained by volumetric testing, and the imbibition oil production and the imbibition equilibrium time are determined according to the height change of the liquid column in the capillary metering tube. The test is carried out using an imbibition experimental device, the upper end of which is connected to a capillary metering tube with a scale, and the lower end is a transparent glass bottle. The specific test method is as follows: the core is completely immersed in a transparent glass bottle filled with water, and the values ​​on the capillary metering tube at different times are recorded. When the values ​​on the capillary metering tube no longer change, it means that the imbibition has reached equilibrium. The time required from the start of the experiment to the imbibition reaching equilibrium is the water imbibition equilibrium time; the water imbibition equilibrium time test is carried out at normal temperature and pressure.

[0019] It can be understood that, in the present invention, the minimum miscibility pressure of formation crude oil and CO2 is greater than the current formation pressure.

[0020] In the oil recovery method of the low permeability oil reservoir of the present invention, the target oil reservoir refers to an oil reservoir that meets the following conditions: average permeability <50.0×10 -3 μm 2 , oil reservoir burial depth>1000m, remaining oil saturation>35%. BRIEF DESCRIPTION OF THE DRAWINGS

[0021] Figure 1 This is a schematic diagram of the results after the pressure-reducing auxiliary agent, carbon dioxide and water are injected into the formation in the present invention;

[0022] Figure 2 It is a schematic diagram of the mechanism of micro-fracturing the formation when injecting water in the present invention;

[0023] Figure 3 Schematic diagram of the mechanism of the Jiamin effect for controlling gas-water fluidity in the present invention;

[0024] Figure 4 Schematic diagram of water imbibition balance curve in an embodiment of the present invention;

[0025] Figure 5 Schematic diagram of the curve of the change of the wellhead pressure over time during the well shut-in stage in the embodiments of the present invention and the comparative examples;

[0026] Figure 6 It is a schematic diagram of the curve of the change of the enhanced oil recovery rate with the production time in the embodiments of the present invention and the comparative examples. DETAILED DESCRIPTION

[0027] The technical solution of the present invention is further described below in conjunction with specific embodiments.

[0028] Example

[0029] The oil recovery method of the low permeability reservoir in this embodiment takes a single well A in a closed small fault block low permeability reservoir as an example. The relevant parameters of the single well A are as follows: the average porosity is 12.8%, the average permeability is 16×10 -3 μm 2 , the oil-bearing area is 0.025km 2 The effective thickness of the oil layer is 25.2m, the original formation pressure is 28.5MPa, the buried depth of the oil reservoir is 2650m, and the remaining oil saturation is >35%; the current formation pressure of the reservoir is 20.5MPa, the minimum miscibility pressure of reservoir crude oil and CO2 is 33.7MPa, and the reservoir fracture pressure is 53MPa.

[0030] The pore volume PV of a single well A = average porosity × oil-bearing area × effective thickness of the oil layer. The effective thickness of the oil layer refers to the thickness of that part of the reservoir that has industrial oil production capacity.

[0031] The oil recovery method of the low permeability oil reservoir of this embodiment specifically comprises the following steps:

[0032] (1) Inject n-pentane into Well A in the form of a slug, with an injection volume of 0.014 PV and an injection rate of 20 t / d. Then inject liquid carbon dioxide into Well A in the form of a slug, with an injection volume of 0.057 PV and an injection rate of 20 t / d. Then continuously inject water into Well A in the form of a slug, with an injection rate of 200 m / s. 3 / d, during the water injection process, the bottom hole pressure change is detected. When the bottom hole pressure reaches 0.8 of the reservoir fracture pressure (i.e. 42.4MPa), microcracks are formed in the reservoir through hydraulic fracturing, and the permeability transformation of the reservoir is completed. The n-pentane and carbon dioxide can be better pushed into the deep microcracks of the reservoir, and then infiltrated into the pores through the matrix, so as to better contact with the reservoir crude oil and expand the affected range. At this time (when the bottom hole pressure reaches 0.8 of the reservoir fracture pressure), the water injection rate is reduced and water injection is continued to ensure that the bottom hole pressure does not exceed the reservoir fracture pressure (53MPa), and the average formation pressure of the reservoir is higher than the original formation pressure (28.5MPa), and the average formation pressure of the reservoir reaches the optimal miscibility pressure (the optimal miscibility pressure is equal to 1.1 times the minimum miscibility pressure, i.e. 37.07MPa) or above. After the average formation pressure of the reservoir reaches the optimal miscibility pressure, carbon dioxide and crude oil can be better mixed. At this time, the fluidity of crude oil becomes better and it is easier to produce;

[0033] (2) Stop water injection, close the oil well, and start to shut down the well. Through indoor permeation experiments, the water permeation equilibrium time is 10 days. The water permeation equilibrium curve is as follows: Figure 4 As shown in Figure 1, the wellhead pressure at the initial stage of the field test was 16.5 MPa. After 20 days, the pressure showed a horizontal trend (i.e., the time required for the wellhead pressure to reach equilibrium during the field well soaking process was 20 days). The equilibrium pressure was 11 MPa, and the pressure drop difference was 5.5 MPa. The curve of the change of the wellhead pressure over time during the soaking stage is shown in Figure 1. Figure 5 As shown, therefore, the soaking time is 30 days (the soaking time is equal to the sum of the pressure drop balance time and the water imbibition balance time, that is, equal to 20 days + 10 days = 30 days). After soaking for 30 days, the single well A is opened for production (spraying production). Among them, the water imbibition balance time is obtained by volumetric test, and the imbibition oil production and the imbibition balance time are determined according to the height change of the liquid column in the capillary metering tube. The test is carried out at room temperature and pressure using an imbibition experimental device. The upper end of the imbibition experimental device is connected to a capillary metering tube with a scale, and the lower end is a transparent glass bottle. The specific test method is as follows: the core is completely immersed in a transparent glass bottle filled with water, and the values ​​on the capillary metering tube at different times are recorded. When the value on the capillary metering tube no longer changes, it means that the imbibition has reached equilibrium. The time required from the start of the experiment to the imbibition reaching equilibrium is the water imbibition balance time.

[0034] Since carbon dioxide exists in the formation (temperature ≥31.1℃, pressure ≥7.38MPa) in a supercritical form, carbon dioxide and water form a Jamin effect in the formation, which can inhibit the large-scale crossflow of gas in the heterogeneous reservoir during the blowout process, slow down the speed and amplitude of the wellhead pressure drop during the blowout, and at the same time extend the oil production cycle and improve the recovery rate. The well has accumulated 1,500 tons of oil in one year, and the recovery rate has increased by 24.1% (the curve of the change of the recovery rate with the production time is shown in Figure 6 shown).

[0035] Comparative Example

[0036] The oil production method of the low permeability reservoir in this comparative example takes single well B as an example. Single well A and single well B are two wells in the same closed structural block with similar geological and production conditions. The relevant parameters of single well B are as follows: the average porosity is 12.6%, the average permeability is 15.8×10 -3 μm 2 The oil-bearing area is 0.026km 2 The effective thickness of the oil layer is 25.2m, the original formation pressure is 28.3MPa, the buried depth of the oil reservoir is 2620m, the remaining oil saturation is greater than 35%, and the difference in the remaining oil saturation between well A and well B does not exceed 5%; the current formation pressure of the reservoir is 20.2MPa, the minimum miscibility pressure of reservoir crude oil and CO2 is 33.4MPa, and the reservoir fracture pressure is 51MPa.

[0037] The oil production method of the low permeability oil reservoir in this comparative example specifically comprises the following steps: injecting liquid carbon dioxide into a single well B, the injection volume is 0.057PV, the injection rate is 20t / d, and after the injection is completed, the well is shut down; the wellhead pressure at the initial stage of the well shut down is 12.4MPa, and after 17 days of well shut down, the wellhead pressure changes in a horizontal trend, the equilibrium pressure is 5MPa, and the pressure drop difference is 7.4MPa. The curve of the change of the wellhead pressure with time during the well shut down stage is as follows: Figure 5 As shown, the well was shut down for 17 days. After 17 days, single well B was opened for production (blowout production).

[0038] Due to the lack of injection of pressure-reducing agent slugs, water slugs and reservoir transformation, the pure carbon dioxide throughput has a small range and cannot form a uniform mixed phase. There is no water slug to suppress the cross-flow of gas in the heterogeneous reservoir during the blowout production. The wellhead pressure drop is fast and the amplitude is large, dropping by 7.4MPa within 17 days. The energy exhaustion speed is fast and the carbon dioxide throughput efficiency is low. The well has accumulated an increase of 600t of oil in one year, and the recovery rate is 12.5% ​​(the curve of the change of recovery rate with production time is shown in Figure 2). Figure 6 shown).

[0039] In addition, in order to investigate the effects of pressure-reducing agent slugs, water slugs and different pressure-reducing agents on the experimental results, single wells C, D and E were selected. Wells A, B, C, D and E were all five wells with similar geological conditions and production conditions in the same closed block (i.e., the average porosity, average permeability, oil-bearing area, effective thickness of oil layer, original formation pressure, reservoir burial depth, remaining oil saturation, current formation pressure of reservoir, minimum miscibility pressure of reservoir crude oil and CO2 or reservoir fracture pressure of wells A, B, C, D and E were not more than 5% different from each other), and then single wells C, D and E were produced. The specific method is as follows:

[0040] For single well C, n-pentane was injected into single well C in the form of a plug, with an injection volume of 0.014PV and an injection rate of 20t / d. Then, liquid carbon dioxide was injected in the form of a plug, with an injection volume of 0.057PV and an injection rate of 20t / d. Then the oil well was closed and well shut-in was started. The shut-in time was equal to the sum of the pressure drop equilibrium time and the water imbibition equilibrium time. After the shut-in was completed, single well C was opened for production (blowing production). The production results showed that the well had a cumulative increase of 820t in oil production within one year, and the recovery rate was increased by 14.2%.

[0041] For single well D, liquid carbon dioxide is injected into single well D in the form of a slug, with an injection volume of 0.057 PV and an injection rate of 20 t / d. Then, water is continuously injected into single well D in the form of a slug, with an injection rate of 200 m / s. 3 / d, during the water injection process, the bottom hole pressure change is detected. When the bottom hole pressure reaches 0.8 of the reservoir fracture pressure, the water injection rate is reduced and water injection is continued to ensure that the bottom hole pressure does not exceed the reservoir fracture pressure, and that the average reservoir formation pressure is higher than the original formation pressure, and that the average reservoir formation pressure reaches the optimal miscibility pressure (the optimal miscibility pressure is equal to 1.1 times the minimum miscibility pressure). Then the water injection is stopped, the oil well is closed, and the well is shut down. The well shut down time is equal to the sum of the pressure drop equilibrium time and the water imbibition equilibrium time. After the well shut down is completed, the single well D is opened for production (blowout production). The production results show that the well has accumulated an increase of 1,105 tons of oil in one year, and the recovery rate has increased by 18.7%.

[0042] For single well E, the method of the embodiment was used for production, except that n-pentane was replaced with oleic acid diethanolamide; the production results showed that the well increased oil production by 1,180 tons in one year, and the recovery rate was increased by 19.6%.

[0043] In summary, when the method of the embodiment is used for mining, a stronger oil-increasing ability and higher economic efficiency are exhibited.

[0044] When the method of the embodiment is used to produce oil in other wells close to well A, the injection amount of n-pentane in the oil production method of the low permeability reservoir of the embodiment is adjusted from 0.014PV to 0.01PV, 0.05PV, or the injection rate of n-pentane is adjusted from 20t / d to 25t / d, 30t / d, or the injection amount of liquid carbon dioxide is adjusted from 0.057PV to 0.05PV, 0.2PV, or the injection rate of liquid carbon dioxide is adjusted from 20t / d to 25t / d, 30t / d, or the water injection rate is adjusted from 200m / d to 25t / d, 30t / d. 3 / d adjusted to 100m 3 / d, 300m 3 / d, or the time corresponding to the reduction of water injection rate is adjusted from 0.8 of the bottom hole pressure reaching the reservoir fracture pressure to 0.95 of the bottom hole pressure reaching the reservoir fracture pressure, or the optimum miscibility pressure is adjusted from 1.1 times of the minimum miscibility pressure to 1.3 times of the minimum miscibility pressure. The oil production results show that the oil recovery rate of the producing wells can reach more than 22% within one year.

Claims

1. A method for oil production in a low permeability reservoir, characterized in that: The method comprises the following steps: respectively injecting a pressure reducing agent and liquid carbon dioxide into a target oil reservoir formation in the form of a segment plug, then injecting water into the formation until the average formation pressure reaches a micro-fracture pressure, reducing the water injection rate, continuing to inject water until the average formation pressure is greater than the original formation pressure and reaches an optimal miscibility pressure, stopping water injection, and then shutting the well and producing; the pressure reducing agent is selected from one or any combination of pentane, hexane, and an oil-soluble surfactant; the micro-fracture pressure is 0.8 to 0.95 of the formation fracture pressure, and the optimal miscibility pressure is equal to 1.1 to 1.3 times the minimum miscibility pressure of the formation crude oil and CO2.

2. The method for producing oil from a low permeability reservoir according to claim 1, wherein: The injection amount of the pressure reducing agent is 0.01-0.05 PV.

3. The oil recovery method for a low permeability reservoir according to claim 1 or 2, characterized in that: The injection rate of the pressure reducing auxiliary agent is 20-30 t / d.

4. The oil recovery method for a low permeability oil reservoir according to claim 1, characterized in that: The injection amount of the liquid carbon dioxide is 0.05-0.2PV.

5. The oil recovery method for a low permeability oil reservoir according to claim 1 or 4, characterized in that: The injection rate of the liquid carbon dioxide is 20-30 t / d.

6. The method for producing oil from a low permeability reservoir according to any one of claims 1, 2 and 4, characterized in that: The water injection speed is 100-300m 3 / d.

7. The method for producing oil from a low permeability reservoir according to any one of claims 1, 2 and 4, characterized in that: The soaking time is equal to the sum of the pressure drop equilibrium time and the water imbibition equilibrium time; the pressure drop equilibrium time is the time required for the wellhead pressure to reach equilibrium during the on-site soaking process.

8. The method for producing oil from a low permeability reservoir according to any one of claims 1, 2 and 4, characterized in that: The target reservoir refers to the reservoir that meets the following conditions: average permeability < 50.0×10 -3 μm 2 , oil reservoir burial depth>1000m, remaining oil saturation>35%.

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