A method for synergistically exploiting CO2 miscible gravity drainage and water-gas alternation

Abstract

The application provides a CO2 miscible gravity drive-water gas alternation cooperative exploitation method, which comprises the following steps: deploying a CO2 injection well at a structural high position of an oil reservoir region, deploying a water gas alternation injection well at a structural low position, and deploying a production well at a structural middle position; determining injection speeds of the CO2 injection well and the water gas alternation injection well and an oil production speed of the production well according to calculation; and monitoring reservoir data and production data during the exploitation process, and adjusting a development technical policy in real time according to a monitoring result, so as to maintain stable production. The method improves the gravity drive oil production speed and shortens the production cycle, and at the same time, ensures that the gas-liquid interface can stably move downward, effectively prevents CO2 gas channeling, and guarantees the stability and sustainability of the development process.

Description

Technical Field

[0001] This invention belongs to the field of CO2 flooding technology and relates to a CO2 miscible gravity flooding-water-gas alternating synergistic extraction method. Background Technology

[0002] Gas injection gravity drive refers to deploying gas injection wells in the high structural parts of an oil reservoir and production wells in the low structural parts. Utilizing the density difference between gas and crude oil, gas accumulates at the top of the structure to form a gas cap. The continuous expansion of the gas cap pushes the oil-gas interface downwards, achieving a stable oil displacement effect. This is an important technological direction for gas drive. CO2 miscible gravity drive is one such method. It not only utilizes the miscibility of CO2 with crude oil to reduce interfacial tension and crude oil viscosity, thus improving displacement efficiency, but also achieves carbon sequestration, helping to mitigate the impact of global warming. It is a highly promising and large-scale enhanced oil recovery method for thick and steeply dipped reservoirs.

[0003] Conventional CO2 miscible gravity flooding development is a rolling development strategy, which involves advancing gradually from high to low structural gradients. Specifically, injection wells are deployed at high structural levels for continuous CO2 injection, while production wells are sequentially deployed along the structural line towards lower structural levels. Once the first row of production wells experiences significant gas channeling and reaches shut-in conditions, they are shut down or converted into injection wells to continue driving the gas-liquid interface downwards. Simultaneously, the second row of production wells takes over production, and this process continues until the last row of production wells is shut down, marking the end of the rolling development cycle. A significant and pressing issue with this conventional CO2 miscible gravity flooding development model is the low overall reservoir production rate, long production cycle, and long investment recovery period. This directly challenges the oilfield in achieving its phased production targets and indicators on time, as this model requires a large number of production wells to be shut down in the downdip structural areas. Furthermore, conventional CO2 miscible gravity flooding requires a large volume of CO2, leading to high gas source costs, especially when CO2 supply is limited. In short, while pursuing stable control of the gas-liquid interface, the conventional rolling development model also faces a profound contradiction between oil production rate and production cycle.

[0004] Therefore, how to innovate development models while ensuring the effectiveness of oilfield development has become an urgent problem to be solved. Summary of the Invention

[0005] To address the technical problems existing in the prior art, this invention provides a CO2 miscible gravity-driven water-gas alternating synergistic extraction method. This method improves the oil production rate and shortens the production cycle, while ensuring that the gas-liquid interface can stably migrate downwards, effectively preventing CO2 gas channeling and ensuring the stability and sustainability of the development process.

[0006] To achieve the above-mentioned technical effects, the present invention adopts the following technical solution:

[0007] This invention provides a method for the synergistic exploitation of CO2 through gravity drive and alternating water and gas processes, the method comprising:

[0008] CO2 injection wells are deployed in the high structural parts of the reservoir area, water-gas alternating injection wells are deployed in the low structural parts, and production wells are deployed in the middle structural parts.

[0009] The injection rates of CO2 injection wells and water-gas alternating injection wells, as well as the oil production rate of production wells, are determined based on calculations, and then extraction is carried out.

[0010] During the extraction process, reservoir data and production data are monitored, and extraction conditions are adjusted in real time based on the monitoring results to maintain stable production.

[0011] As a preferred technical solution of the present invention, CO2 injection wells inject CO2 into the interior of the structure, and CO2 accumulates at the top of the structure to form a gas cap, displacing crude oil and moving downwards.

[0012] As a preferred technical solution of the present invention, water and CO2 are alternately injected into the structure in a water-gas alternating injection well. The water and CO2 generate upward displacement pressure, which drives the crude oil to move upward.

[0013] As a preferred technical solution of the present invention, water is injected into the structure before CO2.

[0014] As a preferred embodiment of the present invention, the maximum critical injection rate of the CO2 injection well is determined by Equation 1:

[0015]

[0016] In the formula, v is the critical injection rate, in m / d; k is the absolute permeability, in mD; k' ro k' represents the relative permeability of the oil phase. rg Δρ is the relative permeability of the gas phase. og The density difference between oil and gas, in kg / m³ 3 μ o Oil phase viscosity, in mPa·s; μ g θ represents the gas phase viscosity, in mPa·s; θ is the formation dip angle.

[0017] As a preferred technical solution of the present invention, the maximum critical injection rate of the CO2 injection well is determined by Equation 2:

[0018] q = Sv

[0019] Formula 2

[0020] In the formula, q is the critical injection rate, in m³. 3 / d; S is the oil-bearing area, in m² 2 .

[0021] As a preferred technical solution of the present invention, the injection rate of the water-gas alternating injection well is 50-80% of the injection rate of the CO2 injection well.

[0022] As a preferred technical solution of the present invention, the gas-water section formed after water and CO2 are injected into the water-gas alternating injection well has a flow ratio of 1:1 to 2.

[0023] As a preferred technical solution of the present invention, the water-gas alternation cycle of injected water and CO2 in the water-gas alternation injection well is 30 to 80 days.

[0024] As a preferred technical solution of the present invention, the production data includes the oil production, gas production, CO2 content, water cut and pressure of the production well, as well as the injection volume and injection pressure of the CO2 injection well and the water-gas alternating injection well.

[0025] Compared with the prior art, the present invention has at least the following beneficial effects:

[0026] (1) This invention provides a CO2 miscible gravity drive-water-gas alternating synergistic exploitation method, which can improve the overall oil production rate of CO2 miscible gravity drive reservoirs and shorten the production cycle to meet the production needs of oil fields.

[0027] (2) This invention provides a CO2 miscible gravity drive-water-gas alternating co-extraction method, which can ensure that the gas-liquid interface can move downward stably, effectively prevent CO2 gas channeling, and ensure the stability and sustainability of the development process.

[0028] (3) This invention provides a CO2 mixed-phase gravity drive-water-gas alternating synergistic mining method, which can reduce costs and increase efficiency, and has economic feasibility and market competitiveness. Attached Figure Description

[0029] Figure 1 A schematic diagram of the CO2 miscible gravity drive-water-gas alternating synergistic exploitation method provided in a specific embodiment of the present invention.

[0030] Figure 2 This is a schematic diagram illustrating the distribution principle of injection wells and production wells in the CO2 miscible gravity drive-water-gas alternating synergistic exploitation method provided by the present invention.

[0031] Figure 3 This is a comparison chart showing the CO2 miscible gravity drive-water-gas alternating synergistic exploitation method provided in this embodiment of the invention and the development process of conventional CO2 miscible gravity drive.

[0032] 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. Detailed Implementation

[0033] The technical solution of this application will be further described below through specific implementation methods.

[0034] This invention provides a method for the synergistic exploitation of CO2 through gravity drive and alternating water and gas phases, comprising:

[0035] CO2 injection wells are deployed in the high structural parts of the reservoir area, water-gas alternating injection wells are deployed in the low structural parts, and production wells are deployed in the middle structural parts.

[0036] The injection rates of CO2 injection wells and water-gas alternating injection wells, as well as the oil production rate of production wells, are determined based on calculations, and then extraction is carried out.

[0037] During the extraction process, reservoir data and production data are monitored, and extraction conditions are adjusted in real time based on the monitoring results to maintain stable production.

[0038] This invention integrates geological structural features with fluid dynamics principles, employing a novel development model of top-injection, bottom-top-production, and center-production. This model involves continuous CO2 injection at the structural high, alternating water-gas injection at the structural low, and oil production in the structural center. By designing alternating water-gas injection at the bottom, a dual driving force (water and CO2) is innovatively introduced to the reservoir bottom. This not only increases the energy replenishment from the structural low upwards but also effectively curbs the disorderly dissipation and pressure escape of CO2 injected at the top, preventing CO2 channeling and ensuring a stable interface migration rate. Furthermore, the bottom-injected CO2 improves displacement efficiency through miscibility with crude oil, effectively promoting the migration and accumulation of crude oil from the low to the structural center. Production wells deployed in the structural center can directly extract the accumulated crude oil from both the top and bottom, achieving immediate response and dynamic balance between extraction and injection. This significantly shortens the production cycle, reduces CO2 demand, and expands the economic feasibility and market competitiveness of gravity gas drive while ensuring improved recovery.

[0039] In one specific embodiment of the present invention, the high structural region refers to the naturally advantageous region for oil and gas migration, and the low structural region refers to the relatively unfavorable region for oil and gas migration.

[0040] In one specific embodiment of the present invention, a production well is deployed in the middle section of the structure, and the production well is located in the optimal path for oil and gas migration.

[0041] In one specific embodiment of the present invention, before deploying CO2 injection wells, water-gas alternating injection wells, and production wells, geological analysis and fluid property analysis of the target reservoir area are performed. The geological analysis includes formation dip angle, formation thickness, internal interlayers, and permeability. The fluid property analysis includes reservoir fluid composition, injected gas composition, the minimum miscibility pressure required for CO2 and crude oil to achieve miscibility under reservoir temperature and pressure conditions, and the density difference between the injected gas and crude oil.

[0042] In one specific embodiment of the present invention, the number and deployment method (such as well spacing and drainage spacing) of CO2 injection wells, water-gas alternating injection wells and production wells can be calculated using geological and numerical simulation software based on the geological information, reservoir distribution and reservoir fluid conditions of the area. The software and methods used are known in the art and will not be further limited here.

[0043] In one specific embodiment of the present invention, CO2 is injected into a CO2 injection well. Through the miscibility of CO2 with crude oil and the gravity differentiation caused by the density difference between CO2 and crude oil, the gravity differentiation results in a larger CO2 sweep volume. The lighter CO2, after injection, accumulates at the top of the structure to form a gas cap, effectively displacing the crude oil and causing it to migrate downwards. The miscibility further enhances the CO2 displacement efficiency, fully utilizing the effects of miscibility, viscosity reduction, and expansion.

[0044] In one specific embodiment of the present invention, water and gas are injected alternately into the well, with water injected into the structure before CO2.

[0045] In one specific embodiment of the present invention, the alternating injection of water and gas increases the displacement pressure from bottom to top in the lower part of the structure, continuously pushing the crude oil in the lower part upward. From the perspective of the displacement medium, firstly, a certain amount of water is alternately injected into the lower part to form a water cushion effect, increasing the bottom pressure and preventing the subsequent CO2 injected into the lower part from rapidly moving upward due to gravitational differentiation. Subsequently, the CO2 injected into the lower part plays a role in mixing with the crude oil, thereby improving the displacement efficiency through miscibility, viscosity reduction, expansion, and other effects.

[0046] In one specific embodiment of the present invention, the perforation location of the high-position gas injection well (CO2 injection well) is located in the upper reservoir of the single well, the perforation location of the low-position injection well (water-gas alternating injection well) is located in the lower reservoir of the single well, and the perforation location of the production well in the middle of the structure is located in the upper reservoir of the single well. When a production well near the high position of the structure is converted into a gas injection well, the perforation level does not need to be adjusted; when a production well near the low position of the structure is converted into a gas injection well, the perforation level in the upper reservoir is sealed, and a new perforation is made in the lower reservoir level.

[0047] In one specific embodiment of the present invention, the maximum critical injection rate of the CO2 injection well is determined by Equation 1:

[0048]

[0049] In the formula, v is the critical injection rate, in m / d; k is the absolute permeability, in mD; k' ro k' represents the relative permeability of the oil phase. rg Δρ is the relative permeability of the gas phase. og The density difference between oil and gas, in kg / m³ 3 μ o Oil phase viscosity, in mPa·s; μ g θ represents the gas phase viscosity, in mPa·s; θ is the formation dip angle.

[0050] In one specific embodiment of the present invention, the minimum injection rate of the CO2 injection well is determined by the injection-production ratio, which is approximately 1:1.

[0051] In one specific embodiment of the present invention, the injection rate is set based on the maximum critical injection rate of the CO2 injection well. The set injection rate cannot be too slow, otherwise an effective gas cap cannot be formed, or the time to form the gas cap is too slow. The set injection rate cannot be too fast, otherwise an unstable gas-liquid interface is easily formed, causing CO2 to break through the production well rapidly.

[0052] In one specific embodiment of the present invention, the maximum critical injection rate is calculated based on the critical injection rate. The maximum critical injection rate of a CO2 injection well is determined by Equation 2:

[0053] q = Sv

[0054] Formula 2

[0055] In the formula, q is the critical injection rate, in m³. 3 / d; S is the oil-bearing area, in m² 2 .

[0056] In one specific embodiment of the present invention, the injection rate of the water-gas alternating injection well is 50% to 80% of the injection rate of the CO2 injection well, such as 50%, 55%, 60%, 65%, 70%, 75%, or 80%, but is not limited to the listed values; other unlisted values ​​within this range are also applicable. If the injection rate is too low, the displacement and miscibility effects in the lower regions are weakened; if the injection rate is too high, the gas injected in the lower regions accelerates its migration towards the higher regions of the structure.

[0057] In one specific embodiment of the present invention, the gas-water slug ratio formed after the injection of water and CO2 in a water-gas alternating injection well is 1:1 to 2, such as 1:1, 1:1.1, 1:1.2, 1:1.3, 1:1.4, 1:1.5, 1:1.6, 1:1.7, 1:1.8, 1:1.9, or 1:2, etc., but not limited to the listed values; other unlisted values ​​within this range are also applicable. By controlling the gas-water slug ratio and the water-gas alternation cycle, the size of the gas and water slugs is controlled to ensure the formation of an effective overall slug for continuous upward displacement, while avoiding CO2 over-proliferation and upward surge, thus ensuring the stability of the upward displacement front at the lower part.

[0058] In one specific embodiment of the present invention, the water-gas alternation cycle of injected water and CO2 in the water-gas alternation injection well is 30 to 80 days, such as 30 days, 35 days, 40 days, 45 days, 50 days, 55 days, 60 days, 65 days, 70 days, 75 days or 80 days, but is not limited to the listed values. Other unlisted values ​​within this range are also applicable.

[0059] In one specific embodiment of the present invention, the injection pressure of the injection wells at high and low structural locations should be based on the surface compressor, the injection well process design and pressure range, and the formation fracturing pressure. The maximum value should not exceed 80% of the maximum pressure of the surface injection equipment and 80% of the formation fracturing pressure.

[0060] In one specific embodiment of the present invention, the production rate of the production well is controlled between 1.5% and 2% of the well-controlled reserves. If the production rate is too low, the overall production cycle will be too long and the economic benefits will be too poor; if the production rate is too high, the production pressure differential will be large, which can easily cause an unstable gas-liquid interface.

[0061] In one specific embodiment of the present invention, the shut-in conditions for production wells should refer to surface gas-liquid separation treatment measures, such as when the gas-oil ratio of the production well exceeds 1500m. 3 / m 3 When this happens, the production well should be shut down or converted into a gas injection well.

[0062] In one specific embodiment of the present invention, by monitoring reservoir production data, performing real-time statistical analysis and trend prediction, evaluating the current development effect, identifying potential problems, and adjusting extraction parameters and injection strategies in a timely manner, the development effect is ensured.

[0063] In one specific embodiment of the present invention, the production data includes the oil production, gas production, CO2 content, water cut and pressure of the production well, as well as the injection volume and injection pressure of the CO2 injection well and the water-gas alternating injection well.

[0064] In one specific embodiment of the present invention, the effectiveness of the new CO2 miscible gravity drive-water-gas alternating synergistic development model is evaluated by three indicators: full life cycle mining time, recovery rate, and cumulative CO2 injection amount.

[0065] To better illustrate the present invention and facilitate understanding of its technical solutions, typical but non-limiting embodiments of the present invention are as follows:

[0066] Example

[0067] This embodiment provides a method for the synergistic exploitation of CO2 through gravity drive and alternating water and gas, the process of which is as follows: Figure 1 As shown, the mining method includes:

[0068] The reservoir has a top depth of 2150m, a length of about 600m, a width of about 250m, a thickness of about 200m, and a dip angle of about 15°. The reservoir has a permeability of 6.1mD in the X and Y directions and a vertical permeability of 1.8mD. There are no interlayers or fractures inside the reservoir. The above conditions are consistent with the geological characteristics of an oil reservoir.

[0069] The reservoir has an average pressure of 23 MPa and an average temperature of 86°C. The injected gas composition is pure CO2, and the calculated CO2 density under these reservoir conditions is 622 kg / m³. 3 It is less than the density of crude oil (730 kg / m³). 3 Under reservoir conditions, CO2 and crude oil will undergo gravity separation. Calculations show that under reservoir temperature and pressure conditions, the minimum miscibility pressure required for CO2 and crude oil to become miscible is 21 MPa, which is less than the reservoir pressure of 23 MPa. Therefore, the injected CO2 can achieve miscibility. The above conditions are consistent with fluid characteristics.

[0070] Based on the numerical simulation optimization results, the well network is deployed according to the collaborative development model of top injection, bottom top and intermediate production. A gas injection well (well1) is deployed in the high part of the structure for continuous CO2 injection. Production wells, namely well2 and well3, are deployed in sequence towards the low part of the structure at a well spacing of 150m. Then, injection wells, named well4, are deployed in the low part of the structure at a well spacing of 150m.

[0071] Well 1 has a perforation depth of 2200-2230m, Well 2 has a perforation depth of 2270-2300m, Well 3 has a perforation depth of 2340-2370m, and Well 4 has a perforation depth of 2410-2440m.

[0072] Based on the optimized calculations of the injection-production balance development technology policy, the gas injection rate of high-position gas injection wells is 10,000 m³ / s. 3 / d, between the minimum injection-production ratio and the critical gas injection rate; injection wells in the structural low-position are injected sequentially in the order of water slug-CO2 slug-water slug, with a water slug injection cycle of 2 months and a CO2 slug injection cycle of 1 month, and the water injection volume is 20-30m³. 3 Fluctuations between / d, gas injection rate 5000m³ 3 / d represents 50% of the top gas injection volume. The maximum injection pressure in the injection well does not exceed 45MPa, which is less than 80% of the maximum pressure withstand by the surface compressor and the formation fracturing pressure.

[0073] Production well yielded 13m³ of oil. 3 / d, the oil production rate is about 1.5%, and the gas-oil ratio of the production well should not exceed 1500m. 3 / m 3 The bottom pressure must not be lower than 5 MPa.

[0074] Real-time monitoring of production data during the development process, including oil production, gas production, water production, gas-oil ratio, formation pressure, and CO2 content, allows for analysis and identification of potential problems, enabling timely adjustments to production parameters and injection strategies. For example, when the injection well pressure exceeds 45 MPa, the gas and water injection rates decrease; when the gas-oil ratio of the production well exceeds 1500 m³ / s... 3 / m 3 Afterwards, the production well is shut down or converted into a gas injection well; when the bottom pressure of the production well is lower than 5MPa, the production output of the production well is reduced.

[0075] According to the simulation results (Table 1), the CO2 miscible gravity drive-water-gas alternating synergistic development method improves upon conventional CO2 miscible gravity drive in three evaluation indicators: total lifecycle development time, oil recovery rate, and cumulative CO2 injection volume. The total lifecycle development time is shortened by 11 years, the oil recovery rate is increased by 2%, and the required CO2 volume is reduced by 48,000 tons. This confirms that the new model proposed in this invention can significantly shorten the total lifecycle development time, improve the recovery rate, reduce CO2 gas supply, and achieve significant cost reduction and efficiency improvement. The reasons can be found in... Figure 3 It is known that conventional CO2 miscible gravity drive requires sequential well drilling in a single row, with a production time of about 10 years per row, which is time-consuming. However, after CO2 miscible gravity drive-water-gas alternation synergistic development, the production rate is significantly increased in the early stage, which is twice that of the conventional mode, and then gradually decreases. Overall, it shortens the effective period and also improves the recovery rate to a certain extent.

[0076] Table 1

[0077]

[0078] The applicant declares that the detailed structural features of the present invention are illustrated through the above embodiments, but the present invention is not limited to the above detailed structural features, that is, it does not mean that the present invention must rely on the above detailed structural features to be implemented. Those skilled in the art should understand that any improvements to the present invention, equivalent substitutions for the components selected in the present invention, additions of auxiliary components, selection of specific methods, etc., all fall within the protection scope and disclosure scope of the present invention.

[0079] The preferred embodiments of the present invention have been described in detail above. However, the present invention is not limited to the specific details in the above embodiments. Within the scope of the technical concept of the present invention, various simple modifications can be made to the technical solution of the present invention, and these simple modifications all fall within the protection scope of the present invention.

[0080] It should also be noted that the various specific technical features described in the above specific embodiments can be combined in any suitable manner without contradiction. In order to avoid unnecessary repetition, the present invention will not describe the various possible combinations separately.

[0081] Furthermore, various different embodiments of the present invention can be combined in any way, as long as they do not violate the spirit of the present invention, they should also be regarded as the content disclosed by the present invention.

Claims

1. A method for the synergistic exploitation of CO2 through gravity drive and alternating water and gas, characterized in that, The mining method includes: CO2 injection wells are deployed in the high structural parts of the reservoir area, water-gas alternating injection wells are deployed in the low structural parts, and production wells are deployed in the middle structural parts. The injection rates of CO2 injection wells and water-gas alternating injection wells, as well as the oil production rate of production wells, are determined based on calculations, and then extraction is carried out. During the extraction process, reservoir data and production data are monitored, and development technology policies are adjusted in real time based on the monitoring results to maintain stable production.

2. The CO2 miscible gravity drive-water-gas alternating synergistic extraction method according to claim 1, characterized in that, The CO2 injection well injects CO2 into the structure, and the CO2 accumulates at the top of the structure to form a gas cap, displacing crude oil and moving downwards.

3. The CO2 miscible gravity drive-water-gas alternating synergistic extraction method according to claim 1, characterized in that, The water-gas alternating injection well alternately injects water and CO2 into the structure, and the water and CO2 generate upward displacement pressure, driving the crude oil upward.

4. The CO2 miscible gravity drive-water-gas alternating synergistic extraction method according to claim 3, characterized in that, Water was injected into the structure before CO2.

5. The CO2 miscible gravity drive-water-gas alternating synergistic extraction method according to claim 1, characterized in that, The maximum critical injection rate of the CO2 injection well is determined by Equation 1: In the formula, v is the critical injection rate, in m / d; k is the absolute permeability, in mD; k r ' o The relative permeability of the oil phase; k r ' g Δρ is the relative permeability of the gas phase. og The density difference between oil and gas, in kg / m³ 3 μ o Oil phase viscosity, in mPa·s; μ g θ represents the gas phase viscosity, in mPa·s; θ is the formation dip angle.

6. The CO2 miscible gravity drive-water-gas alternating synergistic extraction method according to claim 5, characterized in that, The maximum critical injection rate of the CO2 injection well is determined by Equation 2: q = Sv Formula 2 In the formula, q is the critical gas injection rate, in m³ / d; S is the oil-bearing area, in m² / d. 2 .

7. The CO2 miscible gravity drive-water-gas alternating synergistic extraction method according to claim 1, characterized in that, The injection rate of the water-gas alternating injection well is 50-80% of the injection rate of the CO2 injection well.

8. The CO2 miscible gravity drive-water-gas alternating synergistic extraction method according to claim 1, characterized in that, The gas-water section formed after the injection of water and CO2 in the water-gas alternating injection well has a flow ratio of 1:1 to 2.

9. The CO2 miscible gravity-driven water-gas alternating synergistic extraction method according to claim 1, characterized in that, The water-gas alternation injection well has a water-gas alternation cycle of 30 to 80 days.

10. The CO2 miscible gravity-driven water-gas alternating synergistic extraction method according to claim 1, characterized in that, The production data includes the oil production, gas production, CO2 content, water cut and pressure of production wells, as well as the injection volume and injection pressure of CO2 injection wells and water-gas alternating injection wells.

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