A method for oil production by linking multi-medium displacement and huff and puff in a heavy oil reservoir

Abstract

The present application provides a kind of thick oil reservoir multi-medium displacement and linkage of huff and puff oil production method, the oil production method includes: at least two more than injection medium is injected into injection well, injection viscosity reduction energy-increasing system into production well, synchronous displacement and huff and puff, linkage oil production is carried out;The oil production method is developed by multi-well group injection, production well linkage, which greatly improves the recovery of high water cut super deep heavy oil reservoir, and the method can be applied to high water cut heavy oil reservoir with a depth of more than 1800m, which widens the technical limit of heavy oil exploitation.

Description

Technical Field

[0001] This invention relates to the field of oilfield development technology, particularly to the field of heavy oil extraction technology, and especially to a method for oil recovery from heavy oil reservoirs involving multi-media displacement and huff-and-puff linkage. Background Technology

[0002] Currently, thermal recovery technology is mainly used for the development of heavy oil. However, thermal recovery technology is suitable for shallow reservoirs. For deep heavy oil reservoirs, thermal recovery technology results in large heat losses and poor economic benefits.

[0003] Existing ultra-deep heavy oil reservoirs refer to heavy oil reservoirs with a burial depth >1800m, a crude oil viscosity >10000mPa.s under 50℃ conditions after surface degassing, and a permeability <300mD. Thermal recovery and development of such reservoirs is very difficult.

[0004] Currently, the main development method for ultra-deep heavy oil reservoirs is conventional waterflooding. During conventional waterflooding, the deep burial depth, high crude oil viscosity, low permeability, strong heterogeneity, and unreasonable operating conditions create dominant water flow channels in the reservoir with low flow resistance. This easily leads to ineffective water injection, significantly reducing oil recovery and economic benefits; the predicted waterflooding recovery rate is only 13%. Given the problems of dominant water flow channels, small waterflooded volume, rapid water cut increase, and low recovery rate after waterflooding development of ultra-deep heavy oil reservoirs, there is an urgent need to develop advanced recovery technologies to replace waterflooding.

[0005] To address the issues of dominant channels and ineffective water injection during waterflooding, conventional techniques include foam flooding and polymer flooding. Injecting foam or polymer solutions into injection wells can improve the water absorption profile, thereby increasing the water-drive swept volume and improving oil recovery. CN104213870B discloses a method for extracting artificial foam oil from water-flooded heavy oil reservoirs. This method achieves profile modification and oil displacement effects by injecting gelling agents, high-temperature resistant foaming agents, and emulsified viscosity reducers into the injection well. However, this type of profile modification method has poor application results in ultra-deep heavy oil reservoirs with high crude oil viscosity (>10000 mPa·s) and low permeability (<300 mD).

[0006] Currently, gas injection huff and puff technology is also widely used in ultra-deep, extra-heavy oil reservoirs. CN104314539B discloses a method for artificial foam oil huff and puff production in heavy oil reservoirs. By injecting an aqueous solution of foam oil promoter and N2 into the formation, foam oil is formed underground. The dissolution, expansion, and viscosity reduction mechanisms of foam oil are used to improve the single-well productivity and recovery rate of heavy oil reservoirs. CN108071391B proposes an experimental method for huff and puff of natural gas waste gas-propane mixed solvent in the later stage of foam oil reservoirs. By injecting natural gas waste gas-propane mixed solvent, the single-well huff and puff production is improved. CN103244086B proposes an in-situ regenerated foam oil production method for deep heavy oil reservoirs. By injecting light hydrocarbon solvents (C5-C8) and natural gas slugs into the reservoir for huff and puff, the single-well oil production rate and recovery rate are improved. However, during gas injection and huff and puff development, the range of gas action in the reservoir is limited (10-15m) due to the inherent mechanism of huff and puff development, resulting in a limited increase in oil recovery (not exceeding 10%).

[0007] Therefore, how to develop ultra-deep heavy oil reservoirs more economically and efficiently is a pressing problem that needs to be solved in the field of oilfield development. Summary of the Invention

[0008] In view of the problems existing in the prior art, the present invention provides an oil production method for heavy oil reservoirs using multi-media displacement and huff-and-puff linkage, particularly for improving the recovery rate of high water-cut ultra-deep heavy oil reservoirs. This method significantly increases the swept volume and oil displacement efficiency of the displacement medium by injecting a multi-media deep-penetrating viscosity-reducing and profile-modifying displacement system into the injection well. Furthermore, the method significantly increases the utilization radius around the production well by injecting a multi-media deep-penetrating viscosity-reducing and energy-enhancing system into the production well. Through the coordinated development of multiple injection and production wells, the recovery rate of high water-cut ultra-deep heavy oil reservoirs after waterflooding is significantly improved.

[0009] To achieve this objective, the present invention adopts the following technical solution:

[0010] This invention provides a multi-media displacement and huff-and-puff method for oil recovery in heavy oil reservoirs. The method includes: injecting at least two types of displacement media into injection wells, injecting a viscosity-reducing and energy-enhancing system into production wells, and simultaneously displacing and huff-and-puffing to achieve coordinated oil recovery.

[0011] This invention employs a combination of displacement and huff and puff, with continuous injection from the injection well, which can continuously replenish the formation with energy. Compared to huff and puff alone, it can significantly improve the fluid production capacity of huff and puff wells. Moreover, simultaneous injection and production from multiple well groups can avoid the fluid flow dominance caused by pressure fluctuations, achieving uniform sweep and utilization, which can significantly improve recovery efficiency and extend production time.

[0012] In this invention, "multi-medium" refers to a process in which the injected medium consists of two or more injection media.

[0013] The displacement mentioned in this invention refers to the process in which a certain pressure difference exists between the injection well and the production well during the development of an oil and gas field, and the injection medium drives the fluid to the bottom of the production well under the action of a certain pressure difference.

[0014] In this invention, "injection and simmering" refers to the process of injection, well shut-in, and production in the same well during the development of an oil and gas field.

[0015] The heavy oil reservoirs described in this invention refer to heavy oil reservoirs with crude oil viscosity > 10000 mPa.s and permeability < 300 mD at 50°C after surface degassing.

[0016] The oil recovery method described in this invention is particularly suitable for ultra-deep heavy oil reservoirs, that is, heavy oil reservoirs with a burial depth >1800m, a surface degassed crude oil viscosity >10000mPa.s, and a permeability <300mD under 50℃ conditions; furthermore, the oil recovery method described in this invention is especially suitable for oil reservoirs with a water cut greater than 60%.

[0017] Preferably, the injection of at least two displacement media includes sequentially cyclically injecting dimethyl ether slug, CO2 slug, aerosol foaming agent solution, N2 slug, and water slug.

[0018] The present invention preferably uses the above-mentioned displacement media injected sequentially, and combines N2 foam system for profile control with multi-media viscosity reduction. It takes advantage of the high critical pressure, safety, stability and easy access to gas source of N2, and the temperature and salt resistance of the aerosol foam solution system. By injecting N2 and aerosol foam solution system, a good foam profile control effect can be achieved underground, avoiding the situation where CO2 is completely dissolved in oil and water under high pressure and cannot generate bubbles with foam solution.

[0019] This invention optimizes the selection of dimethyl ether and CO2 as a mixed viscosity-reducing system. CO2 has a strong viscosity-reducing and energy-enhancing effect. Under unit pressure, CO2 produces 3.5–4 m³ of dissolved gas per cubic meter of crude oil. 3 / (m 3 Dimethyl ether (DME) has a stronger viscosity-reducing effect and a wider range of applications. DME is a light organic hydrocarbon solvent that is soluble in both oil and water, with a relative density (20℃) of 0.666 and a vapor pressure of 0.5 MPa at room temperature, similar to liquefied petroleum gas (LNG). Under unit pressure, it dissolves 20–45 m³ of gas per cubic meter of crude oil. 3 / (m 3(·MPa). Furthermore, dimethyl ether (DME) is priced at approximately 65% ​​of hydrocarbon gaseous solvents and is a non-toxic, safe, stable, non-oxidizing, and economical organic solvent. When dissolved in water, DME exhibits rapid mass transfer, 3-4 times faster than light hydrocarbon solvents such as propane and butane. Under the same temperature and pressure, DME's viscosity-reducing effect in heavy oil is significantly superior to solvents like CO2, propane, and butane. Utilizing the high pressure of deep reservoirs, injecting DME in conjunction with CO2 facilitates the penetration of both CO2 and DME into the deeper formations, achieving deep viscosity reduction.

[0020] Moreover, the recovery rate of injected dimethyl ether and CO2 is high, reaching over 90%. The produced dimethyl ether and CO2 are easily separated from crude oil under low-pressure conditions. After simple oil and gas separation, they can be reinjected into the formation, thus realizing carbon capture, carbon utilization, and carbon storage, which has significant social and economic benefits.

[0021] Preferably, the volume ratio of the dimethyl ether slug, CO2 slug, N2 slug, and water slug underground is 0.3–0.7:0.9–1.1:0.9–1.1:0.9–1.1, for example, it can be 0.3:0.9:0.9:0.9, 0.4:0.9:0.9:0.9, 0.5:0.9:0.9:0.9, 0.6:0.9:0.9:0.9, 0. 7:0.9:0.9:0.9, 0.5:1:1:1, 0.6:1:1:1, 0.7:1:1:1, 0.4:1.1:1.1:1.1, 0.5:1.0:0.9:0.9, 0.6:1.1:1.0:0.9, or 0.7:1.1:1.1:1.0, etc., but not limited to the listed values; other unlisted values ​​within this range also apply.

[0022] Preferably, the injection amount of the aerosol foaming agent solution is such that the mass concentration of the aerosol foaming agent in the groundwater is controlled at 4-6‰, for example, it can be 4‰, 4.3‰, 4.5‰, 4.7‰, 4.9‰, 5.2‰, 5.4‰, 5.6‰, 5.8‰ or 6‰, but is not limited to the listed values. Other unlisted values ​​within this range are also applicable.

[0023] Preferably, the aerosol foaming agent solution contains a silicone foaming agent, sodium α-olefin sulfonate HL-I, and ethanol.

[0024] Preferably, the silicone-containing foaming agent contains silicone segments, polyoxyethylene, ether groups, and -SO3Na.

[0025] The silicone-containing foaming agent of the present invention preferably contains silicone segments, polyoxyethylene groups, ether groups, etc. These groups are preferred carbon dioxide-loving groups, which have better solubility in carbon dioxide and better foam stabilization effect.

[0026] For example, the structural formula of the silicone-containing foaming agent is as follows: (1)

[0027]

[0028] In the above formula, n is a natural number from 1 to 30, such as 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 15, 20, 22, 25, or 30, but not limited to the listed values. Other unlisted values ​​within this range also apply. m is a natural number from 1 to 40, such as 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 15, 20, 22, 25, 30, 35, or 40, but not limited to the listed values. Other unlisted values ​​within this range also apply.

[0029] The present invention does not impose any special restrictions on the specific molecular weight of sodium α-olefin sulfonate HL-I. For example, sodium α-olefin sulfonate HL-I of C14 to C16 can be used, such as C14, C15 or C16.

[0030] Preferably, the mass fraction of the silicone foaming agent in the aerosol foaming agent solution is 55% to 65%, for example, it can be 55%, 57%, 58%, 59%, 60%, 61%, 62%, 63%, 64% or 65%, etc., but is not limited to the listed values, and other unlisted values ​​within this range are also applicable.

[0031] Preferably, the mass fraction of sodium α-olefin sulfonate HL-I in the aerosol foaming agent solution is 30-40%, for example, it can be 30%, 32%, 33%, 34%, 35%, 36%, 37%, 38%, 39% or 40%, etc., but is not limited to the listed values, and other unlisted values ​​within this range are also applicable.

[0032] Preferably, the mass fraction of ethanol in the aerosol foaming agent solution is 5-10%, for example, it can be 5%, 5.6%, 6.2%, 6.7%, 7.3%, 7.8%, 8.4%, 8.9%, 9.5% or 10%, etc., but is not limited to the listed values. Other unlisted values ​​within this range are also applicable.

[0033] Preferably, the cumulative injection amount of the displacement medium in a single cycle is 0.008 to 0.012 PV, for example, it can be 0.008 PV, 0.0085 PV, 0.0089 PV, 0.0094 PV, 0.0098 PV, 0.0103 PV, 0.0107 PV, 0.0112 PV, 0.0116 PV or 0.012 PV, etc., but is not limited to the listed values. Other unlisted values ​​within this range are also applicable.

[0034] Preferably, the single cycle injection time of the displacement medium is 10 to 30 days, for example, it can be 10 days, 12 days, 13 days, 14 days, 15 days, 26 days, 27 days, 28 days, 29 days or 30 days, but is not limited to the listed values. Other unlisted values ​​within this range are also applicable.

[0035] Preferably, the injection pressure of the displacement medium is controlled below the formation fracturing pressure.

[0036] Preferably, the viscosity-reducing and energy-enhancing system comprises a first dimethyl ether plug, a CO2 co-solvent, a CO2 plug, and a second dimethyl ether plug injected sequentially.

[0037] The present invention preferably involves injecting a CO2 solvent before injecting the CO2 slug into the production well, which is beneficial to improving the dissolution capacity of CO2 and further enhancing the effects of CO2 in dissolving, reducing viscosity, expanding and increasing energy in the formation.

[0038] Preferably, the underground volume ratio of the first dimethyl ether slug, the CO2 slug, and the second dimethyl ether slug is 0.8–1.2:2.8–3.2:0.8–1.2, for example, it can be 0.8:3.0:0.8, 0.9:3.0:0.8, 0.95:3.0:0.8, 1.0:3.0:0.8, 0.8:3.2:1.0, 0.9:3.2:0.8, or 1.0:3. The range of values ​​is 2:0.8, 1.2:3.2:0.8, 0.8:3.2:0.9, 0.9:3.2:0.9, 1.0:3.2:0.9, 1.2:3.2:0.9, 0.8:2.8:1.2, 0.9:2.8:1.2, 1.0:2.8:1.2, or 1.2:2.8:1.2, etc., but is not limited to the listed values. Other unlisted values ​​within this range also apply.

[0039] Preferably, the mass concentration of the CO2 co-solvent is 12-18 wt%, for example, it can be 12 wt%, 13 wt%, 14 wt%, 15 wt%, 16 wt%, 17 wt%, or 18 wt%, etc., but is not limited to the listed values, and other unlisted values ​​within this range are also applicable.

[0040] Preferably, the mass concentration of the CO2 co-solvent in CO2 is controlled to be 3-6‰, for example, it can be 3‰, 3.4‰, 3.7‰, 4‰, 4.4‰, 4.7‰, 5‰, 5.4‰, 5.7‰ or 6‰, but is not limited to the listed values. Other unlisted values ​​within this range are also applicable.

[0041] Preferably, the CO2 co-solvent comprises an amino-azole bifunctionalized ionic solution.

[0042] Preferably, the amino-azole bifunctionalized ionic solution is synthesized by a mixed reaction of diethylenetriamine, imidazole, ethanol and water.

[0043] This invention does not impose any special restrictions on the reaction synthesis process, for example, it can use [DETAH][AHA] synthesized in "Study on CO2 Capture Performance of Amino-Azolium Bifunctional Ionic Liquid Solution", Wu Junhai, Huaqiao University, 2020.

[0044] Preferably, the cumulative injection amount of the viscosity-reducing and energy-enhancing system in a single round is 0.008 to 0.012 PV, for example, it can be 0.008 PV, 0.0085 PV, 0.0089 PV, 0.0094 PV, 0.0098 PV, 0.0103 PV, 0.0107 PV, 0.0112 PV, 0.0116 PV or 0.012 PV, etc., but is not limited to the listed values. Other unlisted values ​​within this range are also applicable.

[0045] Preferably, the single-round injection time of the viscosity-reducing and energy-enhancing system is 3 to 10 days, for example, it can be 3 days, 4 days, 5 days, 6 days, 7 days, 8 days, 9 days or 10 days, but is not limited to the listed values. Other unlisted values ​​within this range are also applicable.

[0046] Preferably, the injection pressure of the viscosity-reducing and energy-enhancing system is controlled below the formation fracturing pressure.

[0047] Preferably, after injection, the production well is allowed to stagnate for 5 to 7 days before being reopened for production. For example, it can be 5 days, 6 days, or 7 days, but it is not limited to the listed values. Other unlisted values ​​within this range are also applicable.

[0048] Preferably, the oil production method includes: water driving to a production well with a water cut > 60 wt%, and then injecting a displacement medium into the injection well. The water cut can be, for example, 60 wt%, 64 wt%, 67 wt%, 70 wt%, 73 wt%, 76 wt%, 79 wt%, 82 wt%, 85 wt%, or 88 wt%, but is not limited to the listed values. Other unlisted values ​​within this range are also applicable.

[0049] Preferably, the oil extraction method includes the following steps:

[0050] (1) Inject at least two types of displacement media into the injection well;

[0051] (2) At the same time as the injection well is stopped, a viscosity-reducing and energy-enhancing system is injected into the production well, and then both the injection well and the production well are stopped for well simmering;

[0052] (3) After the well is sealed, the injection well carries out the injection process of step (1), and the production well simultaneously churns and spits to carry out joint oil production until the daily oil production drops below the production index, and then the single round of production is stopped.

[0053] (4) Repeat steps (2) to (3) to continue production until the water cut of the oil well reaches the water cut index and then stop production.

[0054] This invention employs a multi-media displacement and slug injection method. The synergistic effect of the multi-media system enhances the oil recovery at each stage. For heavy oil reservoirs after waterflooding with high crude oil viscosity, injecting dimethyl ether (DME) slugs into the injection slugs of the injection well first achieves pre-viscosity reduction, improving subsequent profile control. Injecting DME into the production well first, with its stronger viscosity-reducing ability than CO2, pre-viscosities the reservoir and unblocks the wellbore, also improving CO2 injection capacity, allowing later injected CO2 to penetrate deeper into the reservoir. Injecting DME slugs after CO2 slugs facilitates driving CO2 deeper into the reservoir, allowing it to contact a wider area of ​​crude oil and increasing the huff and puff radius.

[0055] The present invention does not impose any special restrictions on the production index, which can be set according to the actual production situation of the oil reservoir, such as 3t / d, 2.5t / d, 2t / d, 1.5t / d or 1.0t / d, etc.

[0056] Preferably, the moisture content is 88-92%, for example, it can be 88%, 88.5%, 89%, 89.5%, 90%, 90.5%, 91%, 91.5%, or 92%, etc.

[0057] As a preferred technical solution of the present invention, the oil extraction method includes the following steps:

[0058] (1) A dimethyl ether slug, a CO2 slug, an aerosolized foaming agent solution, an N2 slug, and a water slug are sequentially circulated into the injection well; wherein the volume ratio of the dimethyl ether slug, CO2 slug, N2 slug, and water slug underground is 0.3-0.7:0.9-1.1:0.9-1.1:0.9-1.1, and the injection amount of the aerosolized foaming agent solution is such that the mass concentration of the aerosolized foaming agent in the groundwater is controlled at 4-6‰, wherein the aerosolized foaming agent solution contains 55-65wt% of a silica-containing foaming agent, 30-40wt% of sodium α-olefin sulfonate HL-I, and 5-10wt% of ethanol; the cumulative injection amount of the displacement medium in a single cycle is 0.008-0.012PV, the injection time is 10-30 days, and the injection pressure is controlled below the formation fracture pressure;

[0059] (2) While the injection well is stopped, dimethyl ether first stage plug, CO2 co-solvent, CO2 stage plug and dimethyl ether second stage plug are injected into the production well in sequence. The cumulative injection volume in a single round is 0.008 to 0.012 PV, the injection time in a single round is 3 to 10 days, the injection pressure is controlled below the formation fracture pressure, and then both the injection well and the production well are stopped and the wells are shut down for 5 to 7 days.

[0060] The underground volume ratio of the first dimethyl ether plug, the CO2 plug, and the second dimethyl ether plug is 0.8–1.2:2.8–3.2:0.8–1.2. The mass concentration of the CO2 co-solvent is 12–18 wt%, and the mass concentration of the CO2 co-solvent in CO2 is controlled to be 3–6‰. The CO2 co-solvent includes an amino-azole bifunctional ionic solution.

[0061] (3) After the well is sealed, the injection well carries out the injection process of step (1), and the production well simultaneously churns and spits to carry out joint oil production until the daily oil production drops below the production index, and then the single round of production is stopped.

[0062] (4) Repeat steps (2) to (3) to continue production until the water cut of the oil well reaches the water cut index and then stop production.

[0063] The method for calculating the mass of the injected gases (CO2, dimethyl ether, N2) in this invention is as follows:

[0064]

[0065] Where m is the mass of injected CO2, dimethyl ether, and N2, and t; V R The underground volume for injecting CO2, dimethyl ether, and N2 is m. 3 ;P R Formation pressure, MPa; T R denoted as formation temperature (°C), and M represents the molecular weights of CO2, dimethyl ether, and N2, which are 0.044 g / mol, 0.046 g / mol, and 0.028 g / mol, respectively.

[0066] In this invention, the PV involved in injection wells and the PV involved in production wells are not the same. According to conventional knowledge in the field, the PV of injection wells = well network area × thickness × porosity; the PV of production wells = π × 50 × 50 × thickness × porosity.

[0067] Compared with the prior art, the present invention has at least the following beneficial effects:

[0068] (1) The oil recovery method of multi-media displacement and huff and puff linkage for heavy oil reservoirs provided by the present invention is particularly suitable for water-cut heavy oil reservoirs with a reservoir depth greater than 1800m after water flooding, which broadens the boundaries of heavy oil extraction technology.

[0069] (2) The multi-media deep enhanced viscosity reduction and profile modification displacement system injected into the heavy oil reservoir multi-media displacement and huff-and-puff linkage oil production method provided by this invention can significantly improve the uniformity of interlayer mobility around the injection well. The alternating injection of dimethyl ether, CO2, aerosolized foam solution, N2, and water in the injection well can significantly improve the oil-water mobility ratio, increase the water drive swept volume, and improve the oil displacement efficiency. For example... Figure 2 As shown, after conventional waterflooding, in the initial stage of injection, the middle layer with good physical properties exhibits a clear dominant water flow channel, and the waterflood front develops most rapidly. As the multi-media system displacement progresses, the dominant channels in the middle layer with good physical properties are pushed back by the multi-media system injected from the production well, and the dominant channels are blocked. Simultaneously, due to the alternating injection of the multi-media system in the injection well, the displacement front becomes increasingly consistent with the displacement fronts of the upper and lower layers with poorer physical properties, and the degree of mobilization around the injection well becomes increasingly uniform.

[0070] (3) The multi-media deep enhancement viscosity reduction and energy enhancement system injected into the oil production method of multi-media displacement and huff-and-puff linkage for heavy oil reservoirs provided by this invention can significantly improve the uniformity and range of interlayer activation around the production well. For example Figure 2 As shown, the injected CO2 and dimethyl ether preferentially enter the water-dominant channel, sealing the high water-cut layer. The remaining CO2 and dimethyl ether enter the surrounding oil layer. The dimethyl ether dissolves in the crude oil, producing a viscosity-reducing effect. As the production well continues to produce, the dispersed CO2 gas and crude oil form foam oil underground, producing an expansion viscosity-reducing effect. The synergistic effect of these two mechanisms can significantly improve the viscosity-reducing effect around the wellbore. With the increase of the number of huff and puff cycles, the radius of the huff and puff front expands further into the oil layer, typically around 50m, and can reach a maximum of 60-70m.

[0071] (4) The oil recovery method of multi-media displacement and huff and puff linkage for heavy oil reservoirs provided by the present invention can extend the development life cycle of heavy oil reservoirs by more than 1 time, increase peak production by 1 to 2 times, and increase recovery rate by more than 35%. Attached Figure Description

[0072] Figure 1 This is a schematic diagram showing the distribution of injected slugs in the oil layer during the displacement and churn process in a specific embodiment of the present invention.

[0073] Figure 2 This is a schematic diagram of the front development process of the multi-media displacement and huff-and-puff linkage oil recovery method provided by the present invention.

[0074] Figure 3 This is a schematic diagram of the development process of the front edge of a conventional single-swallowing development.

[0075] Figure 4 This is a schematic diagram of the development process at the front of conventional water drive development.

[0076] Figure 5This is the daily oil production curve of the oil recovery method in Example 1, which involves conventional water flooding followed by multi-media displacement and huff-and-puff linkage.

[0077] Figure 6 This is the daily oil production curve of the oil recovery method in Example 2, which involves multi-media displacement and linkage between nitrogen huff and puff. Detailed Implementation

[0078] The technical solution of the present invention will be further described below with reference to the accompanying drawings and specific embodiments.

[0079] The present invention will now be described in further detail. However, the examples described below are merely simplified examples of the present invention and do not represent or limit the scope of protection of the present invention. The scope of protection of the present invention is determined by the claims.

[0080] It should be understood that in the description of this invention, the terms "first," "second," etc., are used for descriptive purposes only and should not be construed as indicating or implying relative importance or implicitly specifying the number of indicated technical features. Therefore, a feature defined with "first," "second," etc., may explicitly or implicitly include one or more of that feature. In the description of this invention, unless otherwise stated, "a plurality of" means two or more.

[0081] This invention provides a method for oil recovery from heavy oil reservoirs using multi-media displacement and huff-and-puff linkage, the method comprising the following steps:

[0082] (1) A dimethyl ether slug, a CO2 slug, an aerosolized foaming agent solution, an N2 slug, and a water slug are sequentially circulated into the injection well; wherein the volume ratio of the dimethyl ether slug, CO2 slug, N2 slug, and water slug underground is 0.3-0.7:0.9-1.1:0.9-1.1:0.9-1.1, and the injection amount of the aerosolized foaming agent solution is such that the mass concentration of the aerosolized foaming agent in the groundwater is controlled at 4-6‰, wherein the aerosolized foaming agent solution contains 55-65wt% of a silica-containing foaming agent, 30-40wt% of sodium α-olefin sulfonate HL-I, and 5-10wt% of ethanol; the cumulative injection amount of the displacement medium in a single cycle is 0.008-0.012PV, the injection time is 10-20 days, and the injection pressure is controlled below the formation fracture pressure;

[0083] (2) While the injection well is stopped, dimethyl ether first stage plug, CO2 co-solvent, CO2 stage plug and dimethyl ether second stage plug are injected into the production well in sequence. The cumulative injection volume in a single round is 0.008 to 0.012 PV, the injection time in a single round is 3 to 10 days, the injection pressure is controlled below the formation fracture pressure, and then both the injection well and the production well are stopped and the wells are shut down for 5 to 7 days.

[0084] The underground volume ratio of the first dimethyl ether plug, the CO2 plug, and the second dimethyl ether plug is 0.8–1.2:2.8–3.2:0.8–1.2. The mass concentration of the CO2 co-solvent is 12–18 wt%, and the mass concentration of the CO2 co-solvent in CO2 is controlled to be 3–6‰. The CO2 co-solvent includes an amino-azole bifunctional ionic solution.

[0085] (3) After the well is sealed, the injection well carries out the injection process of step (1), and the production well simultaneously churns and spits to carry out joint oil production until the daily oil production drops below the production index, and then the single round of production is stopped.

[0086] (4) Repeat steps (2) to (3) to continue production until the water cut of the oil well reaches the water cut index and then stop production.

[0087] A schematic diagram of the distribution of injected slugs within the oil reservoir during the displacement and huff-and-puff process in a specific embodiment of the present invention is shown below. Figure 1 As shown in the diagram, this scheme is applicable to the front development process in heterogeneous ultra-deep heavy oil reservoirs. Figure 2 As shown in the diagram, the development process of the leading edge of a conventional swallowing / ejaculation is illustrated in the figure below. Figure 3 As shown in the diagram, the leading edge development of a conventional water-drive system is as follows: Figure 4 As shown, Figures 2-4 In the middle, ① initial displacement leading edge; ② middle displacement leading edge; ③ late displacement leading edge; (i) initial engulfing leading edge; (ii) middle engulfing leading edge; (iii) late engulfing leading edge; from Figures 2-4 As can be seen from the combination, the method provided by the present invention can synergistically combine throughput and displacement, and the two achieve a synergistic mining effect.

[0088] Example 1

[0089] This embodiment discloses a field implementation plan for an ultra-deep heavy oil reservoir in Xinjiang, and compares the oil recovery effect of the multi-media displacement and huff-and-puff linkage method for heavy oil reservoirs provided by this invention with the waterflooding effect for ultra-deep heavy oil reservoirs. The CO2 co-solvent used in this embodiment is [DETAH][Im] synthesized in Section 2.3 of "Study on CO2 Capture Performance of Amino-Azolium Bifunctionalized Ionic Liquid Solution", Wu Junhai, Huaqiao University, 2020.

[0090] reservoir parameters

[0091] The well network parameters are a 140m inverse nine-point well network (production-injection ratio 3:1), with an adjacent production well spacing of 100m. The basic reservoir parameters are as follows: central reservoir depth 2550m, average effective oil layer thickness 50m, initial oil saturation 0.65, average porosity 25%, average permeability 269mD, initial formation pressure 31.9MPa, pressure coefficient 1.25, reservoir temperature 80℃, and underground crude oil viscosity 550mPa·s. At 50℃, the crude oil viscosity is 10500mPa·s, and the crude oil density is 0.966g / cm³. 3 The reservoir was put into production in 2006, and the original development method was mainly conventional water injection. After 16 years of development, the formation pressure was 25 MPa, the water cut was 80%, and the water drive recovery rate was 12.0%.

[0092] (1) Injection scheme of injection well

[0093] 326.3 tons of dimethyl ether slug (600 m³ underground volume) were sequentially injected into the central injection well. 3 ), CO2 slug 561.8t (underground volume 1080m³) 3 ), 110t of aerosol foaming agent solution (5wt%), and 397.2t of N2 slug (underground volume 1200m³). 3 ), water blockade 1100t (underground volume 1100m³) 3 The injection duration was as follows: dimethyl ether injection for 2 days, CO2 injection for 3 days, aerosol foam solution (specifically composed of 55wt% silicone-containing foaming agent (as shown in formula (1), n ​​= 4, m = 3), 35wt% C14 sodium α-olefin sulfonate HL-I and 10wt% ethanol) injection for 2 days, N2 injection for 2 days, and water injection for 10 days. The total injection duration was 19 days per injection.

[0094] (2) Production well injection scheme

[0095] First cycle: Inject 108.8t (200m³ underground volume) of dimethyl ether slug into each production well sequentially. 3 ), CO2 co-solvent (6.2t, 15wt%), CO2 slug 312.1t (underground volume 600m³) 3 ), 108.8t of dimethyl ether slug (200m³ underground volume) 3 The injection times for each segment of the plug were 1 day, 0.5 hours, 2 days, and 1 day, respectively.

[0096] Then injection into both the injection well and the production well was stopped, and the wells were left to stagnate for 5 days.

[0097] (3) After the well is shut down, the injection well carries out the injection process of step (1), and the production well simultaneously churns and spits to carry out joint oil production until the daily oil production drops below 2t / d, at which point the single-cycle production is stopped.

[0098] (4) Repeat steps (2) to (3) to continue production until the water cut of the oil well reaches 95 wt% or more, then stop production.

[0099] In this embodiment, the daily oil production curve of the heavy oil reservoir multi-media displacement and huff-and-puff combined oil recovery method provided in this embodiment is as follows after conventional waterflooding. Figure 5 As shown. From Figure 5 As can be seen from the production situation, before implementation, the daily oil production of conventional waterflooding had dropped to about 2 t / d. After implementing multi-media displacement and huff-and-puff synergistic oil recovery, the daily oil production increased significantly, with the peak daily oil production after implementation being about twice the peak daily oil production before implementation. Implementing multi-media displacement and huff-and-puff synergistic oil recovery can significantly extend the well development time. As shown in Table 1, it is predicted that continued conventional waterflooding development can produce for 6 years, with a final recovery rate of 12.8%. However, the multi-media displacement and huff-and-puff synergistic oil recovery method provided by this invention can continue for approximately 24 years, with a final recovery rate of 48.6%. Compared with conventional extraction, the recovery rate is increased by 35.8% throughout the entire development phase.

[0100] Table 1

[0101]

[0102] Example 2

[0103] This embodiment discloses a field implementation plan for an ultra-deep heavy oil reservoir and compares the oil recovery effect of the multi-media displacement and huff-and-puff linkage method for heavy oil reservoirs provided by this invention with that of huff-and-puff production in ultra-deep heavy oil reservoirs. The CO2 co-solvent used in this embodiment is [DETAH][Tz] synthesized in Section 2.3 of "Study on CO2 Capture Performance of Amino-Azolium Bifunctionalized Ionic Liquid Solution", Wu Junhai, Huaqiao University, 2020.

[0104] reservoir parameters

[0105] The well network parameters are a 140m reverse nine-point well network (production-injection ratio 3:1), with an adjacent production well spacing of 100m. The basic reservoir parameters are as follows: central reservoir depth 2750m, average effective oil layer thickness 45m, initial oil saturation 0.68, average porosity 23%, average permeability 300mD, initial formation pressure 35MPa, pressure coefficient 1.27, reservoir temperature 82℃, underground crude oil viscosity 350mPa·s. At 50℃, the crude oil viscosity is 16000mPa·s, and the crude oil density is 0.946g / cm³. 3 The reservoir began production in 2015, initially developed using nitrogen injection huff and puff. After eight rounds of huff and puff, the formation pressure dropped to 20 MPa, and the current recovery rate is 7.5%.

[0106] (1) Injection scheme of injection well

[0107] 510.7 tons of dimethyl ether slug (450 m³ underground volume) were sequentially injected into the central injection well. 3 ), CO2 slug 267.0t (underground volume 900m³) 3 100t of aerosol foaming agent solution (5wt%), and 325.0t of N2 slug (underground volume 900m³). 3 ), 1000t water blockade (underground volume 1000m³) 3 The injection duration was as follows: dimethyl ether injection for 2 days, CO2 injection for 2 days, aerosolized foam solution (specifically composed of 58 wt% silicone-containing foaming agent (as shown in formula (1), n ​​= 6, m = 1), 30 wt% C16 sodium α-olefin sulfonate HL-I and 12 wt% ethanol) injection for 1 day, N2 injection for 2 days, and water injection for 10 days. The total injection duration was 17 days per injection.

[0108] (2) Production well injection scheme

[0109] First cycle: Inject 106.8t (180m³ underground volume) of dimethyl ether slug sequentially into each production well. 3 ), CO2 co-solvent (9.6t, 16wt%), CO2 slug 306.4t (underground volume 540m³) 3 ), 106.8t of dimethyl ether slug (underground volume 180m³) 3 The injection times for each segment plug were 1 day, 0.5 hours, 2 days, and 1 day, respectively.

[0110] Then injection into both the injection well and the production well was stopped, and the wells were left to stagnate for 5 days.

[0111] (3) After the well is shut down, the injection well carries out the injection process of step (1), and the production well simultaneously churns and pumps to carry out joint oil production until the daily oil production drops below 1.5t / d, at which point the single-cycle production is stopped.

[0112] (4) Repeat steps (2) to (3) to continue production until the water cut of the oil well reaches 95 wt% or more, then stop production.

[0113] like Figure 6As shown, from a production perspective, before the implementation of this embodiment, the daily oil production from conventional huff and puff production had decreased to approximately 4.5 t / d. After implementing the multi-media displacement and huff and puff combined oil production method, the daily oil production increased significantly, with the peak daily oil production after implementation being approximately five times that before implementation. Implementing multi-media displacement and huff and puff combined oil production can significantly extend the well development time. As shown in Table 2, it is predicted that continued nitrogen huff and puff development can produce for 12 years, with a final recovery rate of 9.9%. The extraction method of this invention can continue for approximately 31 years, with a final recovery rate of 48.1%. Compared to nitrogen huff and puff development, the recovery rate is increased by 38.2% throughout the entire development phase.

[0114] Table 2

[0115]

[0116]

[0117] Example 3

[0118] This embodiment discloses a multi-media displacement and huff-and-puff oil recovery method for a certain ultra-deep heavy oil reservoir. The CO2 co-solvent used in this embodiment is [DETAH][Py] synthesized in Section 2.3 of "Study on CO2 Capture Performance of Amino-Azolium Bifunctionalized Ionic Liquid Solution", Wu Junhai, Huaqiao University, 2020.

[0119] reservoir parameters

[0120] The well network parameters are a 212m inverse nine-point well network (production-injection ratio 3:1), with an adjacent production well spacing of 150m. The basic reservoir parameters are as follows: central reservoir depth 2500m, average effective oil layer thickness 40m, initial oil saturation 0.65, average porosity 26%, average permeability 230mD, initial formation pressure 30MPa, pressure coefficient 1.2, reservoir temperature 79℃, and underground crude oil viscosity 150mPa·s. At 50℃, the crude oil viscosity is 10000mPa·s, and the crude oil density is 0.926g / cm³. 3 .

[0121] (1) Injection scheme of injection well

[0122] 666.7 tons of dimethyl ether slug (1300 m³ underground volume) were sequentially injected into the central injection well via circulation. 3 ), CO2 slug 1275.4t (underground volume 2600m³) 3 ), aerosol foaming agent solution (6wt%) 167t, N2 slug 796.0t (underground volume 2550m³) 3 ), water blockade 2000t (underground volume 2000m³) 3The injection duration was as follows: dimethyl ether injection for 4 days, CO2 injection for 6 days, aerosolized foam solution (specifically composed of 60 wt% silicone-containing foaming agent (as shown in formula (1), n ​​= 2, m = 10), 35 wt% C15 sodium α-olefin sulfonate HL-I and 5 wt% ethanol) injection for 1 day, N2 injection for 3 days, and water injection for 15 days. The total injection duration was 29 days per injection.

[0123] (2) Production well injection scheme

[0124] First cycle: Inject 102.6t (200m³ underground volume) of dimethyl ether slug into each production well sequentially. 3 ), CO2 co-solvent (11.9t, 12wt%), CO2 slug 284.5t (underground volume 580m³) 3 ), 92.3t of dimethyl ether slug (underground volume 180m³) 3 The injection times for each segment plug were 1 day, 0.5 hours, 2 days, and 1 day, respectively.

[0125] Then injection into both the injection well and the production well was stopped, and the wells were left to stagnate for 7 days.

[0126] (3) After the well is shut down, the injection well carries out the injection process of step (1), and the production well simultaneously churns and pumps to carry out joint oil production until the daily oil production drops below 2.5t / d, at which point the single-cycle production is stopped.

[0127] (4) Repeat steps (2) to (3) to continue production until the water cut of the oil well reaches 90 wt% or more, then stop production.

[0128] Example 4

[0129] This embodiment discloses a multi-media displacement and huff-and-puff oil recovery method for a certain ultra-deep heavy oil reservoir. The CO2 co-solvent used in this embodiment is [DETAH][Im] synthesized in Section 2.3 of "Study on CO2 Capture Performance of Amino-Azolium Bifunctionalized Ionic Liquid Solution", Wu Junhai, Huaqiao University, 2020.

[0130] reservoir parameters

[0131] The well network parameters are a 106m inverse nine-point well network (production-injection ratio 3:1), with an adjacent production well spacing of 75m. The basic reservoir parameters are as follows: central reservoir depth 1850m, effective oil layer thickness 60m, initial oil saturation 0.65, average porosity 25%, average permeability 100mD, initial formation pressure 22MPa, pressure coefficient 1.19, reservoir temperature 60℃, and underground crude oil viscosity 250mPa·s. At 50℃, the crude oil viscosity is 18000mPa·s, and the crude oil density is 0.966g / cm³. 3 .

[0132] (1) Injection scheme of injection well

[0133] 159.0 t of dimethyl ether slug (400 m³ underground volume) was sequentially injected into the central injection well. 3 ), CO2 slug 266.2t (underground volume 700m³) 3 ), aerosol foaming agent solution (4wt%) 125t, N2 slug 193.6t (underground volume 800m³) 3 ), 1000t water blockade (underground volume 1000m³) 3 The injection duration was as follows: dimethyl ether injection for 2 days, CO2 injection for 3 days, aerosol foam solution (specifically composed of 62wt% silicone-containing foaming agent (as shown in formula (1), n ​​= 10, m = 4), 33wt% C16 sodium α-olefin sulfonate HL-I and 5wt% ethanol) injection for 2 days, N2 injection for 2 days, and water injection for 11 days. The total injection duration was 20 days per injection.

[0134] (2) Production well injection scheme

[0135] First cycle: Inject 91.4t (230m³ underground volume) of dimethyl ether slug into each production well sequentially. 3 ), CO2 co-solvent (8.2t, 18wt%), CO2 slug 244.9t (underground volume 644m³) 3 ), 73.1t of dimethyl ether slug (underground volume 184m³) 3 The injection times for each segment plug were 2 days, 3 hours, 3 days, and 2 days, respectively.

[0136] Then injection into both the injection well and the production well was stopped, and the wells were left to stagnate for 7 days.

[0137] (3) After the well is sealed, the injection well carries out the injection process of step (1), and the production well simultaneously churns and spits to carry out joint oil production until the daily oil production drops below 3t / d, at which point the single-cycle production is stopped.

[0138] (4) Repeat steps (2) to (3) to continue production until the water cut of the oil well reaches 92wt% or more, then stop production.

[0139] In summary, the oil recovery method for heavy oil reservoirs that combines multi-media displacement and huff-and-puff linkage provided by this invention significantly improves both the available development time and the final recovery rate compared to huff-and-puff alone or water flooding alone. It achieves the synergistic effect of displacement and huff-and-puff, significantly improving the oilfield recovery rate and increasing the recovery rate of heavy oil by more than 35%.

[0140] The present invention has been illustrated with the above embodiments to describe the detailed process features of the present invention. However, the present invention is not limited to the above detailed process features, that is, it does not mean that the present invention must rely on the above detailed process features to be implemented. Those skilled in the art should understand that any improvements to the present invention, equivalent substitutions for the steps selected in the present invention, additions of auxiliary steps, selection of specific methods, etc., all fall within the protection scope and disclosure scope of the present invention.

Claims

1. A method for oil recovery in heavy oil reservoirs involving multi-media displacement and huff-and-puff linkage, characterized in that, The oil production method includes: injecting at least two types of displacement media into the injection well, injecting a viscosity-reducing and energy-enhancing system into the production well, and simultaneously displacing and huffing / puffing to achieve coordinated oil production; The injection of at least two displacement media includes sequentially cyclically injecting dimethyl ether slug, CO2 slug, aerosol foaming agent solution, N2 slug, and water slug. The viscosity-reducing and energy-enhancing system comprises sequentially injected dimethyl ether first-stage plug, CO2 co-solvent, CO2 stage plug and dimethyl ether second-stage plug; The cumulative injection amount of the displacement medium in a single cycle is 0.008~0.012PV; the cumulative injection amount of the viscosity-reducing and energy-enhancing system in a single cycle is 0.008~0.012PV. After injection, the production well is left to simmer for 5-7 days before being reopened for production.

2. The oil extraction method according to claim 1, characterized in that, The volume ratio of the dimethyl ether slug, CO2 slug, N2 slug, and water slug underground is 0.3~0.7:0.9~1.1:0.9~1.1:0.9~1.

1.

3. The oil extraction method according to claim 2, characterized in that, The injection volume of the aerosol foaming agent solution is such that the mass concentration of the aerosol foaming agent in the groundwater is controlled at 4-6‰.

4. The oil extraction method according to claim 1, characterized in that, The aerosol foaming agent solution contains a silicone foaming agent, sodium α-olefin sulfonate HL-I, and ethanol.

5. The oil extraction method according to claim 4, characterized in that, The mass fraction of silicone foaming agent in the aerosol foaming agent solution is 55-65%.

6. The oil extraction method according to claim 4, characterized in that, The mass fraction of sodium α-olefin sulfonate HL-I in the aerosol foaming agent solution is 30~40%.

7. The oil extraction method according to claim 4, characterized in that, The mass fraction of ethanol in the aerosol foaming agent solution is 5-10%.

8. The oil extraction method according to any one of claims 1 to 7, characterized in that, The single-cycle injection time of the displacement medium is 10 to 30 days.

9. The oil extraction method according to claim 1, characterized in that, The injection pressure of the displacement medium is controlled below the formation fracturing pressure.

10. The oil extraction method according to any one of claims 1 to 7, characterized in that, The underground volume ratio of the first dimethyl ether plug, the CO2 plug, and the second dimethyl ether plug is 0.8~1.2:2.8~3.2:0.8~1.

2.

11. The oil extraction method according to claim 1, characterized in that, The mass concentration of the CO2 co-solvent is 12~18wt%.

12. The oil extraction method according to claim 1, characterized in that, The mass concentration of the CO2 co-solvent in CO2 is controlled to be 3-6‰.

13. The oil extraction method according to any one of claims 1 to 7, characterized in that, The CO2 co-solvent includes an amino-azole bifunctionalized ionic solution.

14. The oil extraction method according to claim 13, characterized in that, The amino-azole bifunctionalized ionic solution is synthesized by a mixed reaction of diethylenetriamine, imidazole, ethanol and water.

15. The oil extraction method according to any one of claims 1 to 7, characterized in that, The single-round injection time of the viscosity-reducing and energy-enhancing system is 3 to 10 days.

16. The oil extraction method according to claim 15, characterized in that, The injection pressure of the viscosity-reducing and energy-enhancing system is controlled below the formation fracturing pressure.

17. The oil extraction method according to any one of claims 1 to 7, characterized in that, The oil production method includes: water driving to a production well with a water cut > 60 wt%, and then injecting a displacement medium into the injection well.

18. The oil extraction method according to claim 1, characterized in that, The oil extraction method includes the following steps: (1) Inject at least two types of displacement media into the injection well; (2) At the same time as the injection well is stopped, a viscosity-reducing and energy-enhancing system is injected into the production well, and then both the injection well and the production well are stopped for well simmering; (3) After the well is sealed, the injection well carries out the injection process of step (1), and the production well simultaneously churns and spits to carry out joint oil production until the daily oil production drops below the production index, at which point the single round of production is stopped. (4) Repeat steps (2) to (3) to continue production until the water content of the oil well reaches the water content index and then stop production.

Images