A method for integrated water control and oil stabilization in a heavy oil reservoir with edge and bottom water

Abstract

The application discloses a method for integrated water control and oil stabilization of edge-bottom water thickened oil reservoirs, which utilizes a composite combination mode to fully exert the synergistic effect among N2 foam+CO2 viscosity reducer+N2 huff and puff, the injection of N2 foam compresses the downward movement of water cone, slows down the bottom water coning, CO2 viscosity reducer cooperates with deep propulsion, greatly reduces the viscosity of crude oil, N2 high elasticity displaces crude oil, and supplements the formation pressure, so that the edge-bottom water producing range is enlarged, and the edge-bottom water thickened oil reservoir water control and oil stabilization technology is innovatively proposed to slow down the bottom water coning, reduce the viscosity of crude oil, inhibit the water content rise, and thus improve the oil reservoir recovery factor. The research result can provide a reference basis for the formulation of mining technical schemes and the optimization of injection-production parameters of similar block edge-bottom water thickened oil reservoirs after entering the high water cut period.

Description

Technical Field

[0001] This invention belongs to the field of edge-bottom water heavy oil reservoir regulation and driving technology, specifically involving an integrated water control and oil stabilization method for edge-bottom water heavy oil reservoirs. Background Technology

[0002] In the development of heavy oil reservoirs with edge and bottom water, the presence of edge and bottom water affects the oil production effect. Compared with conventional heavy oil reservoirs, this type of reservoir has a series of production problems such as early water breakthrough in oil wells, short waterless production period, rapid increase in water cut, high production cost, and low economic benefits, resulting in a generally low recovery rate.

[0003] Currently, commonly used cold recovery technologies in heavy oil reservoirs with bottom water include CO2 huff and puff, N2 huff and puff, viscosity reducer-assisted CO2 huff and puff, and N2 + foam huff and puff. Among these, N2 foam technology has advantages such as inhibiting bottom water coning, adjusting the oil-water profile, sealing large channels, and reducing oil-water interfacial tension. Viscosity reducer CO2 technology has a significant dual viscosity-reducing effect, significantly reducing crude oil viscosity, increasing crude oil fluidity, and effectively reducing asphaltene precipitation, but it also faces problems such as poor inhibition of bottom water coning and limited reservoir energy replenishment. CO2 huff and puff technology has advantages such as dissolution-based viscosity reduction, dissolved gas-driven oil recovery, and extraction of light components, but its formation energy decays rapidly, and its ability to inhibit bottom water coning is insufficient.

[0004] This invention utilizes the advantages and synergistic effects of N2, foam, CO2, and viscosity reducers to provide a water control and oil stabilization technology for heavy oil reservoirs with edge and bottom water, achieving the effects of suppressing bottom water coning, increasing well production, and improving oil recovery. Numerical simulations were used to study the economic limits of injection and production parameters for the water control and oil stabilization technology scheme, using the production-input ratio as an indicator to determine the technical scheme and parameters for the water control and oil stabilization technology. This research can provide a reference for the formulation of development schemes and the optimization of injection and production parameters for related heavy oil reservoirs with edge and bottom water. Summary of the Invention

[0005] The purpose of this section is to outline some aspects of embodiments of the present invention and to briefly describe some preferred embodiments. Simplifications or omissions may be made in this section, as well as in the abstract and title of this application, to avoid obscuring the purpose of these documents; however, such simplifications or omissions should not be construed as limiting the scope of the invention.

[0006] In view of the problems existing in the above and / or prior art, the present invention is proposed.

[0007] Therefore, the purpose of this invention is to overcome the shortcomings of the prior art and provide a method for integrated water control and oil stabilization in heavy oil reservoirs with edge and bottom water.

[0008] To solve the above-mentioned technical problems, the present invention provides the following technical solution: including,

[0009] include,

[0010] Based on the actual mining model, the unit where the huff and puff well is located is extracted, and the CMG reservoir numerical simulation software STARS simulator is used to construct a conceptual model of heavy oil with edge and bottom water.

[0011] Using cumulative oil production and output-input ratio as evaluation indicators, the injection timing of the integrated water control and oil stabilization system, the injection amount of each additive in the system, and the well shut-in time after all additives are injected are determined according to the model simulation output, so as to obtain the regulation and drive scheme of the integrated water control and oil stabilization system for heavy oil reservoirs with edge and bottom water.

[0012] The integrated water-control and oil-stabilizing system consists of N2 foam, viscosity reducer, CO2, and N2, which are injected sequentially during the regulation and drive process.

[0013] As a preferred embodiment of the integrated water control and oil stabilization method for edge-bottom water heavy oil reservoirs described in this invention, the method for determining the injection timing includes:

[0014] The design simulates the implementation of integrated water control and oil stabilization under different water content schemes, and obtains the cumulative oil production of each scheme;

[0015] Calculate the output-input ratio under different moisture content schemes, taking into account the investment cost;

[0016] The injection timing of the integrated water control and oil stabilization system is determined by using cumulative oil production and output-input ratio as evaluation indicators.

[0017] As a preferred embodiment of the integrated water control and oil stabilization method for heavy oil reservoirs with edge and bottom water as described in this invention, the injection amount of each additive in the system is determined by sequentially determining the injection amounts of N2-foam, viscosity reducer, CO2, and N2.

[0018] As a preferred embodiment of the integrated water control and oil stabilization method for heavy oil reservoirs with edge and bottom water as described in this invention, the method for determining the injection amount of N2-foam includes:

[0019] Based on the technical parameters of the determined injection timing, different N2-foam gas-liquid ratio schemes were designed, and the cumulative oil production of each scheme was simulated. The N2-foam gas-liquid ratio scheme was determined by using the cumulative oil production as an indicator.

[0020] Based on the determined N2-foam gas-liquid ratio scheme, different N2-foam injection volume schemes were designed, and the cumulative oil production of each scheme was obtained through model simulation.

[0021] Considering the investment cost, calculate the output-input ratio under different N2-foam injection schemes;

[0022] The technical parameters for N2-foam injection volume are determined using cumulative oil production and output-input ratio as evaluation indicators.

[0023] As a preferred embodiment of the integrated water control and oil stabilization method for heavy oil reservoirs with edge and bottom water according to the present invention, the method for determining the injection amount of the viscosity reducer includes,

[0024] Based on the determined technical parameters of N2-foam injection volume, different injection volume schemes for viscosity reducers were designed, and the cumulative oil production of each scheme was obtained through model simulation.

[0025] Taking into account the injection cost, calculate the output-input ratio under different viscosity reducer injection schemes;

[0026] The amount of viscosity reducer to be injected is determined by using cumulative oil production and output-input ratio as evaluation indicators.

[0027] As a preferred embodiment of the integrated water control and oil stabilization method for edge-bottom water heavy oil reservoirs described in this invention, the method for determining the CO2 injection amount includes:

[0028] Based on the determined technical parameters of the viscosity reducer injection amount, different CO2 injection schemes were designed, and the cumulative oil production of each scheme was obtained through model simulation.

[0029] Taking into account the cost of injection, calculate the output-input ratio under different CO2 injection schemes;

[0030] The amount of CO2 injected is determined by using cumulative oil production and the output-input ratio as evaluation indicators.

[0031] As a preferred embodiment of the integrated water control and oil stabilization method for heavy oil reservoirs with edge and bottom water according to the present invention, the method for determining the well shut-in time includes,

[0032] Based on the technical parameters of the determined N2 injection volume, different well-closing time schemes were designed, and the cumulative oil production of each scheme was obtained through model simulation.

[0033] Taking into account the investment costs, calculate the output-input ratio under different well-closing time schemes;

[0034] The well shut-in time is determined using cumulative oil production and output-to-input ratio as evaluation indicators.

[0035] As a preferred embodiment of the integrated water control and oil stabilization method for edge-bottom water heavy oil reservoirs described in this invention, the method comprises: the injection timing of the integrated water control and oil stabilization system, the injection amount of each additive in the system, and the well shut-in time after all additives are injected, which constitute the adjustment and drive scheme for edge-bottom water heavy oil reservoirs.

[0036] As a preferred embodiment of the integrated water control and oil stabilization method for heavy oil reservoirs with edge and bottom water as described in this invention, the recovery rate achieved by the adjustment and drive method is >15% higher than that before adjustment and drive.

[0037] Beneficial effects of this invention:

[0038] To fully leverage and combine the advantages of various extraction methods and compensate for their respective shortcomings, this invention utilizes the triple mechanism of N2-foam blocking waterways, CO2 viscosity reducer dissolution and energy enhancement, and deep penetration to supplement formation energy with N2. It innovatively proposes a water control and oil stabilization technology for heavy oil reservoirs with edge and bottom water to slow down bottom water coning, reduce crude oil viscosity, inhibit water cut rise, and thus improve reservoir recovery. Attached Figure Description

[0039] To more clearly illustrate the technical solutions of the embodiments of the present invention, the drawings used in the description of the embodiments will be briefly introduced below. Obviously, the drawings described below are only some embodiments of the present invention. For those skilled in the art, other drawings can be obtained based on these drawings without creative effort. Wherein:

[0040] Figure 1 This is the reservoir conceptual model of Embodiment 2 of the present invention.

[0041] Figure 2 This is a curve for determining the appropriate injection timing in Embodiment 2 of the present invention.

[0042] Figure 3 This is the curve for determining the N2-foam gas-liquid ratio in Example 2 of the present invention.

[0043] Figure 4 This is a curve for determining the N2-foam injection amount in Embodiment 2 of the present invention.

[0044] Figure 5 This is a curve showing the determination of the amount of viscosity reducer injected in Example 2 of the present invention.

[0045] Figure 6 This is a curve for determining the CO2 injection amount in Embodiment 2 of the present invention.

[0046] Figure 7 This is a curve for determining the N2 injection amount in Embodiment 2 of the present invention.

[0047] Figure 8 This is a curve for determining the optimal well-clogging time in Embodiment 2 of the present invention. Detailed Implementation

[0048] To make the above-mentioned objects, features and advantages of the present invention more apparent and understandable, the specific embodiments of the present invention will be described in detail below with reference to the examples in the specification.

[0049] Many specific details are set forth in the following description in order to provide a full understanding of the invention. However, the invention may also be practiced in other ways different from those described herein, and those skilled in the art can make similar extensions without departing from the spirit of the invention. Therefore, the invention is not limited to the specific embodiments disclosed below.

[0050] Secondly, the term "one embodiment" or "embodiment" as used herein refers to a specific feature, structure, or characteristic that may be included in at least one implementation of the present invention. The phrase "in one embodiment" appearing in different places in this specification does not necessarily refer to the same embodiment, nor is it a single or selective embodiment that is mutually exclusive with other embodiments.

[0051] The relevant parameters for calculating the output-input ratio in this invention are:

[0052] The cost of N2 is 15,000 yuan / 10,000 cubic meters, foaming agent is 5,000 yuan / ton, CO2 is 8,000 yuan / ton, viscosity reducer is 6,000 yuan / ton, and oil price is 0.25 yuan / m3;

[0053] The viscosity reducer used in this invention is VR-3 viscosity reducer.

[0054] Unless otherwise specified, all other raw materials used in this invention are commercially available in the field.

[0055] Example 1

[0056] This embodiment provides a method for integrated water control and oil stabilization in heavy oil reservoirs with edge and bottom water, specifically as follows:

[0057] S1: Establish a conceptual model for simulating water-controlled and oil-stabilized heavy oil reservoirs with edge and bottom water:

[0058] Based on the actual mine model, the unit where the throughput well is located is extracted, and the corresponding conceptual model is constructed using the CMG reservoir numerical simulation software STARS simulator.

[0059] S2: Through the optimization study of the economic limits of injection and production parameters, the recommended technical parameters for injection timing are determined using cumulative oil production and output-input ratio as evaluation indicators.

[0060] Specifically, the simulation uses the different water cuts of the production well as the injection timings to simulate reasonable injection timings and calculate the output-input ratio at that timing, thereby optimizing reasonable injection timings.

[0061] First, the cumulative oil production of each scheme is obtained by designing water control and oil stabilization technologies under different water contents. Second, the output-input ratio under different water contents schemes is calculated based on the injection cost. Finally, the reasonable injection timing is determined by using the cumulative oil production and output-input ratio as evaluation indicators.

[0062] S3: Through the study of optimizing the economic limits of injection and production parameters, the recommended technical parameters for N2 foam injection volume are determined using cumulative oil production and output-input ratio as evaluation indicators.

[0063] After determining the appropriate injection timing, the injection parameters of the water control and oil stabilization technology, namely the N2-foam + CO2 viscosity reducer + N2 huff and puff scheme, were optimized.

[0064] First, various gas-liquid ratio schemes were designed and simulated to obtain the cumulative oil production; second, the optimal gas-liquid ratio was determined by comparing the cumulative oil production.

[0065] Based on the optimized gas-liquid ratio, the N2 foam injection dosage was further optimized. First, different N2-foam injection schemes were designed and simulated to obtain the cumulative oil production of each scheme. Second, the output-input ratio under different N2 foam injection schemes was calculated considering the injection cost. Finally, the N2-foam injection parameters were determined using the cumulative oil production and output-input ratio as evaluation indicators.

[0066] S4: Through the study of optimizing the economic limits of injection and production parameters, the recommended technical parameters for the injection amount of viscosity reducer are determined using cumulative oil production and output-input ratio as evaluation indicators.

[0067] Injection of viscosity reducers can significantly reduce crude oil viscosity. Based on the previously optimized parameters, the dosage of viscosity reducer injection will continue to be optimized.

[0068] First, multiple different viscosity reducer injection dosage schemes were designed and simulated to obtain the cumulative oil production of each scheme. Second, the output-input ratio under different viscosity reducer injection dosage schemes was calculated based on the injection cost. Finally, the viscosity reducer injection parameters were determined using the cumulative oil production and output-input ratio as evaluation indicators.

[0069] S5: Through the study of optimizing the economic limits of injection and production parameters, the recommended technical parameters for CO2 injection volume are determined using cumulative oil production and output-input ratio as evaluation indicators.

[0070] After CO2 is injected into the reservoir, it dissolves in the crude oil and viscosity reducer. The synergistic effect of the two reduces the viscosity of the crude oil again. Based on the optimized viscosity reducer dosage, the CO2 dosage is further optimized.

[0071] First, multiple injection volume schemes were designed and simulated to obtain the cumulative oil production of each scheme. Second, the output-input ratio under different CO2 injection volume schemes was calculated based on the injection cost. Finally, the CO2 injection parameters were determined using the cumulative oil production and output-input ratio as evaluation indicators.

[0072] S6: Through the study of optimizing the economic limits of injection and production parameters, the recommended technical parameters for the N2 injection volume in the final stage are determined using cumulative oil production and output-input ratio as evaluation indicators.

[0073] The N2 injected in the final stage demonstrates the N2 over-coverage effect, which redistributes the formation oil-water interface, replenishes formation energy, and improves production and recovery.

[0074] First, various N2 injection schemes with different injection volumes were designed and simulated to obtain the cumulative oil production of each scheme. Second, the output-input ratio under different N2 injection volume schemes was calculated based on the injection cost. Finally, the N2 injection parameters for the final stage were determined using the cumulative oil production and output-input ratio as evaluation indicators.

[0075] S7: Through research on the optimization of economic limits of injection and production parameters, and using cumulative oil production and output-input ratio as evaluation indicators, the recommended technical parameters for reasonable well shut-in time are determined.

[0076] The duration of well simmering is crucial for the injection and discharge scheme. Too short or too long a time will prevent the injected material from fully exerting its effect, so the well simmering time needs to be optimized.

[0077] First, different well-closing time schemes were designed and simulated to obtain the cumulative oil production of each scheme; second, the output-input ratio under different well-closing time schemes was calculated based on the investment cost; finally, the reasonable well-closing time was determined by using the cumulative oil production and output-input ratio as evaluation indicators.

[0078] S8: Based on the technical parameters of the injection timing, injection volume, and well simmering time of the integrated water control and oil stabilization system determined in steps S1 to S7, a driving adjustment scheme is constructed and the driving adjustment is carried out.

[0079] Example 2

[0080] Reference Figures 1 to 8 To verify the beneficialness of the present invention, this embodiment provides a practical application method of the integrated water control and oil stabilization method for heavy oil reservoirs with edge and bottom water, specifically as follows:

[0081] S1: Establish a conceptual model for simulating water-controlled and oil-stabilized heavy oil reservoirs with edge and bottom water:

[0082] Based on the reservoir physical properties (porosity 33.7%, permeability 1000mD) and actual production conditions (1 horizontal well, 1095 production days) of the heavy oil field block, a typical field model describing water control and oil stabilization of a simulated heavy oil reservoir with edge and bottom water was established using the CMG reservoir numerical simulation software STARS simulator.

[0083] like Figure 1As shown, the model has a grid size of 10m×10m×1m, with a total of 10710 grids. A horizontal well is placed in the model as a throughput well, with a length of 300m. The well location is from grid 11 to grid 40 in the I direction, in grid 11 in the middle of the grid in the J direction, and in grid 2 in the K direction.

[0084] S2: Through the optimization study of the economic limits of injection and production parameters, the recommended technical parameters for injection timing are determined using cumulative oil production and output-input ratio as evaluation indicators.

[0085] Under the condition that other parameters remain unchanged, four schemes for implementing water control and oil stabilization technology under different water contents (90%, 92%, 94%, 96%) were designed.

[0086] After the model runs, each scheme outputs the cumulative oil production of each scheme and calculates the output-input ratio under different water cut schemes.

[0087] Using cumulative oil production and output-input ratio as evaluation criteria, a reasonable injection timing is determined, and the results are as follows: Figure 2 As shown in the figure, the optimal injection and extraction time is when the water cut is 92%.

[0088] S3: Through the study of optimizing the economic limits of injection and production parameters, the recommended technical parameters for N2-foam injection volume are determined using cumulative oil production and output-input ratio as evaluation indicators.

[0089] Under the condition that other parameters remain unchanged and the water content is 92% as the injection time, five schemes for implementing water control and oil stabilization technology are designed under different N2-foam gas-liquid ratios (1:1.5, 1:1, 1:2, 1.5:1, 2:1).

[0090] After the model runs, the cumulative oil production of each scheme is output. Using the cumulative oil production as the evaluation criterion, the optimal gas-liquid ratio is determined. The results are as follows: Figure 3 As shown, the optimal gas-liquid ratio is 1:1.

[0091] Based on the optimized 1:1 gas-liquid ratio, the N2-foam injection dosage was further optimized. Under the condition that other parameters remained unchanged (injection timing was 92% water content), five schemes for implementing water control and oil stabilization technology were designed under different N2-foam injection volumes (45,000 cubic meters, 40,000 cubic meters, 35,000 cubic meters, 30,000 cubic meters, and 25,000 cubic meters, where gas volume is the volume under standard conditions and liquid volume is the volume converted to underground volume when the gas-liquid ratio is 1:1).

[0092] After the model runs, each scheme outputs the cumulative oil production of each scheme and calculates the output-input ratio under different schemes.

[0093] The optimal N2-foam injection rate was determined using cumulative oil production and the output-input ratio as evaluation criteria. The results are as follows: Figure 4 As shown, the optimal N2-foam injection volume is 40,000 cubic meters.

[0094] S4: Through the study of optimizing the economic limits of injection and production parameters, the recommended technical parameters for the injection amount of viscosity reducer are determined using cumulative oil production and output-input ratio as evaluation indicators.

[0095] Under the condition that other parameters remain unchanged (injection time is 92% water content, N2 foam gas-liquid ratio is 1:1, and injection volume is 40,000 cubic meters), five schemes for implementing water control and oil stabilization technology under different viscosity reducer injection volumes (40 tons, 30 tons, 20 tons, 10 tons, and 5 tons) are designed.

[0096] After the model runs, the cumulative oil production of each scheme is output, and the output-input ratio under different viscosity reducer injection amounts is calculated.

[0097] Using cumulative oil production and output-input ratio as evaluation criteria, the optimal viscosity reducer injection amount was determined, and the results are as follows: Figure 5 As shown, the optimal injection amount of viscosity reducer is 30 tons.

[0098] S5: Through the study of optimizing the economic limits of injection and production parameters, the recommended technical parameters for CO2 injection volume are determined using cumulative oil production and output-input ratio as evaluation indicators.

[0099] Under the condition that other parameters remain unchanged (injection timing is 92% water content, N2 foam gas-liquid ratio is 1:1, injection volume is 40,000 cubic meters, and viscosity reducer injection volume is 30 tons), five schemes for implementing water control and oil stabilization technology under different CO2 injection volumes (300 tons, 200 tons, 150 tons, 100 tons, and 50 tons) are designed.

[0100] After the model runs, the cumulative oil production of each scheme is output, and the output-input ratio under different CO2 injection schemes is calculated.

[0101] The optimal CO2 injection rate was determined using cumulative oil production and the output-input ratio as evaluation criteria. The results are as follows: Figure 6 As shown, the optimal CO2 injection rate is 200 tons.

[0102] S6: Through the study of optimizing the economic limits of injection and production parameters, the recommended technical parameters for the N2 injection volume in the final stage are determined using cumulative oil production and output-input ratio as evaluation indicators.

[0103] Under the condition that other parameters remain unchanged (injection timing is 92% water content, N2 foam gas-liquid ratio is 1:1, injection volume is 40,000 cubic meters, viscosity reducer injection volume is 30 tons, and CO2 injection volume is 200 tons), five schemes for implementing water control and oil stabilization technology under different N2 injection volumes (40,000 cubic meters, 30,000 cubic meters, 20,000 cubic meters, 10,000 cubic meters, and 5,000 cubic meters) are designed.

[0104] After the model runs, the cumulative oil production of each scheme is output, and the output-input ratio under different N2 injection schemes is calculated.

[0105] Using cumulative oil production and the output-input ratio as evaluation criteria, the optimal N2 injection rate was determined, and the results are as follows: Figure 7 As shown, the optimal N2 injection amount in the final stage is 20,000 cubic meters.

[0106] S7: Through research on the optimization of economic limits of injection and production parameters, and using cumulative oil production and output-input ratio as evaluation indicators, the recommended technical parameters for reasonable well shut-in time are determined.

[0107] Under the condition that other parameters remain unchanged (injection timing is 92% water cut, N2 foam gas-liquid ratio is 1:1, injection volume is 40,000 cubic meters, viscosity reducer injection volume is 30 tons, CO2 injection volume is 200 tons, and final N2 injection volume is 30,000 cubic meters), five schemes for implementing water control and oil stabilization technology are designed under different well-closing times (25 days, 20 days, 15 days, 10 days, and 5 days).

[0108] After the model runs, each scheme outputs the cumulative oil production of each scheme and calculates the production-input ratio under different well-keeping times.

[0109] The optimal well-closing time was determined using cumulative oil production and the output-to-input ratio as evaluation criteria. The results are as follows: Figure 8 The optimal well-sealing time shown is 10 days.

[0110] S8: Based on the technical parameters of the injection timing, injection volume, and well simmering time of the integrated water control and oil stabilization system determined in steps S1 to S7, a driving adjustment scheme is constructed and the driving adjustment is carried out.

[0111] The optimal technical solution is as follows: when the water content is 92%, inject 40,000 cubic meters of N2 foam with a gas-liquid ratio of 1:1, inject 30 tons of viscosity reducer, inject 200 tons of CO2, inject 30,000 cubic meters of N2 in the final stage, and shut-in the well for 10 days.

[0112] Under this scheme, the output-input ratio is >8.5, the cumulative oil production is >4765 cubic meters, and the recovery rate is increased by 16%.

[0113] Comparative Example 1

[0114] The difference between this comparative example and Example 2 is that the adjustment and drive system is changed from the integrated water control and oil stabilization system to an N2-foam, viscosity reducer, and CO2 system. Specifically, step S6 of Example 2 is omitted, and the remaining steps are the same as in Example 2. The determined adjustment and drive scheme consists of the injection timing of the integrated water control and oil stabilization system, the injection amount of N2-foam, the injection amount of viscosity reducer, the injection amount of CO2, and the well simmering time.

[0115] Comparative Example 2

[0116] The difference between this comparative example and Example 2 is that the adjustment and drive system is changed from an integrated water control and oil stabilization system to a viscosity reducer and CO2 system. Specifically, steps S3 and S6 of Example 2 are omitted, and the remaining steps are the same as those of Example 2. The determined adjustment and drive scheme consists of the injection timing of the integrated water control and oil stabilization system, the injection amount of the viscosity reducer, the injection amount of CO2, and the well simmering time.

[0117] Comparative Example 3

[0118] The difference between this comparative example and Example 2 is that the adjustment and drive system is changed from the integrated water control and oil stabilization system to the N2-foam system. Specifically, steps S4 to S6 of Example 2 are omitted, and the remaining steps are the same as those of Example 2. The determined adjustment and drive scheme consists of the injection timing of the integrated water control and oil stabilization system, the N2-foam injection volume, and the well shut-in time.

[0119] Comparative Example 4

[0120] The difference between this comparative example and Example 2 is that the adjustment and driving system is changed from the integrated water control and oil stabilization system to a viscosity reducer. Specifically, steps S3, S5, and S6 of Example 2 are omitted, and the remaining steps are the same as those of Example 2. The determined adjustment and driving scheme consists of the injection timing of the integrated water control and oil stabilization system, the injection amount of the viscosity reducer, and the well simmering time.

[0121] Comparative Example 5

[0122] The difference between this comparative example and Example 2 is that the adjustment and drive system is changed from the integrated water control and oil stabilization system to CO2. Specifically, steps S3, S4, and S6 of Example 2 are omitted, and the remaining steps are the same as those of Example 2. The determined adjustment and drive scheme consists of the injection timing of the integrated water control and oil stabilization system, the CO2 injection volume, and the well simmering time.

[0123] Comparative Example 6

[0124] The difference between this comparative example and Example 2 is that the adjustment and driving system is changed from the integrated water control and oil stabilization system to N2. Specifically, steps S3 to S5 of Example 2 are omitted, and the remaining steps are the same as those of Example 2. The determined adjustment and driving scheme consists of the injection timing of the integrated water control and oil stabilization system, the N2 injection volume, and the well simmering time.

[0125] The improvement in reservoir recovery rate under different dynamic driving systems in Example 2 and Comparative Examples 1-6 is shown in Table 1.

[0126] Table 1

[0127]

[0128] As can be seen from Table 1, the adjustment and drive system of the present invention can give full play to and combine the advantages of various mining methods, make up for their respective shortcomings, and utilize the triple action mechanism of N2-foam blocking waterways, CO2 viscosity reducer dissolution and energy enhancement, deep propulsion and N2 replenishing formation energy, while taking into account slowing down bottom water coning, reducing crude oil viscosity, and inhibiting water cut rise, thereby achieving the effect of improving reservoir recovery.

[0129] Comparative Example 7

[0130] The difference between this comparative example and Example 2 is that the injection order of each additive in the integrated water control and oil stabilization system is adjusted to viscosity reducer, CO2, N2-foam, N2, while the parameters of the remaining steps are the same as those in Example 2, thus obtaining the driving scheme of this comparative example.

[0131] Comparative Example 8

[0132] The difference between this comparative example and Example 2 is that the injection order of each additive in the integrated water control and oil stabilization system is adjusted to viscosity reducer, CO2, N2, N2-foam. The parameters of the remaining steps are the same as those in Example 2, thus obtaining the driving scheme of this comparative example.

[0133] Comparative Example 9

[0134] The difference between this comparative example and Example 2 is that the injection order of each additive in the integrated water control and oil stabilization system is adjusted to N2, N2-foam, viscosity reducer, and CO2. All other step parameters are the same as in Example 2, thus obtaining the driving scheme of this comparative example.

[0135] Comparative Example 10

[0136] The difference between this comparative example and Example 2 is that the injection order of each additive in the integrated water control and oil stabilization system is adjusted to N2, viscosity reducer, CO2, N2-foam, etc., while the parameters of the remaining steps are the same as those in Example 2, thus obtaining the driving scheme of this comparative example.

[0137] The improvement in reservoir recovery under different additive injection sequences in the same dynamic driving system as Comparative Examples 7-10 in Example 2 is shown in Table 2.

[0138] Table 2

[0139]

[0140] As can be seen from Table 2, the present invention effectively improves the oil recovery rate by optimizing the injection sequence of each additive in the system. This is because the interaction between N2 foam, viscosity reducer, CO2 and N2 during the additive injection process is very complex. In the present invention, N2 foam is first used to inhibit bottom water coning and adjust the oil-water profile. Then, the viscosity of crude oil is reduced by viscosity reducer and CO2. Finally, N2 is added to replenish reservoir energy. The three work synergistically. If the order of the system is adjusted, not only will the synergistic effect of the three be reduced, but the effect of the additives themselves may even be inhibited due to the difference in reservoir conditions.

[0141] In summary, this invention discloses an integrated water control and oil stabilization method for edge-bottom water heavy oil reservoirs. By employing a composite combination approach, it fully leverages the synergistic effects of various components. The injection of N2-foam compresses the water cone downwards, slowing down bottom water coning; CO2 viscosity reducer synergistically advances deeper, significantly reducing crude oil viscosity; and the high elasticity of N2 displaces crude oil, replenishing formation pressure. This expands the range of edge-bottom water utilization. This innovative water control and oil stabilization technology for edge-bottom water heavy oil reservoirs slows down bottom water coning, reduces crude oil viscosity, inhibits water cut increases, and thus improves reservoir recovery. The results of this study can provide a reference for formulating exploitation strategies and optimizing injection and production parameters for similar edge-bottom water heavy oil reservoirs entering the high water-cut stage.

[0142] It should be noted that the above embodiments are only used to illustrate the technical solutions of the present invention and are not intended to limit it. Although the present invention has been described in detail with reference to preferred embodiments, those skilled in the art should understand that modifications or equivalent substitutions can be made to the technical solutions of the present invention without departing from the spirit and scope of the technical solutions of the present invention, and all such modifications or substitutions should be covered within the scope of the claims of the present invention.

Claims

1. A method for integrated water control and oil stabilization in heavy oil reservoirs with edge and bottom water, characterized in that: include, Based on the actual mining model, the unit where the huff and puff well is located is extracted, and the CMG reservoir numerical simulation software STARS simulator is used to construct a conceptual model of heavy oil with edge and bottom water. Using cumulative oil production and output-input ratio as evaluation indicators, the injection timing of the integrated water control and oil stabilization system, the injection amount of each additive in the system, and the well shut-in time after all additives are injected are determined according to the model simulation output, so as to obtain the regulation and drive scheme of the integrated water control and oil stabilization system for heavy oil reservoirs with edge and bottom water. The integrated water-control and oil-stabilizing system consists of N2 foam, viscosity reducer, CO2, and N2, which are injected sequentially during the regulation and drive process. The method for determining the injection timing of the integrated water control and oil stabilization system includes, The design simulates the implementation of integrated water control and oil stabilization under different water content schemes, and obtains the cumulative oil production of each scheme; Calculate the output-input ratio under different moisture content schemes, taking into account the investment cost; The injection timing of the integrated water control and oil stabilization system is determined by using cumulative oil production and output-input ratio as evaluation indicators. The method for determining the injection amount of each additive in the system includes, Based on the technical parameters of the determined injection timing, different N2-foam gas-liquid ratio schemes were designed, and the cumulative oil production of each scheme was simulated. The N2-foam gas-liquid ratio scheme was determined by using the cumulative oil production as an indicator. Based on the determined N2-foam gas-liquid ratio scheme, different N2-foam injection volume schemes were designed, and the cumulative oil production of each scheme was obtained through model simulation. Considering the investment cost, calculate the output-input ratio under different N2-foam injection schemes; The technical parameters for N2-foam injection volume were determined using cumulative oil production and output-input ratio as evaluation indicators. Based on the determined technical parameters of N2-foam injection volume, different injection volume schemes for viscosity reducers were designed, and the cumulative oil production of each scheme was obtained through model simulation. Taking into account the injection cost, calculate the output-input ratio under different viscosity reducer injection schemes; The amount of viscosity reducer to be injected is determined using cumulative oil production and output-input ratio as evaluation indicators. Based on the determined technical parameters of the viscosity reducer injection amount, different CO2 injection schemes were designed, and the cumulative oil production of each scheme was obtained through model simulation. Taking into account the cost of injection, calculate the output-input ratio under different CO2 injection schemes; The amount of CO2 injected is determined using cumulative oil production and the output-input ratio as evaluation indicators. Based on the determined technical parameters of CO2 injection volume, different N2 injection volume schemes are designed, and the cumulative oil production of each scheme is obtained through model simulation. Taking into account the betting costs, calculate the output-input ratio under different N2 injection schemes; The N2 injection volume is determined using cumulative oil production and output-input ratio as evaluation indicators; The method for determining the well-sealing time includes, Based on the technical parameters of the determined N2 injection volume, different well-closing time schemes were designed, and the cumulative oil production of each scheme was obtained through model simulation. Taking into account the investment costs, calculate the output-input ratio under different well-closing time schemes; The well shut-in time is determined using cumulative oil production and output-to-input ratio as evaluation indicators.

2. The method for integrated water control and oil stabilization of edge-bottom water thick oil reservoirs according to claim 1, characterized in that: The injection timing of the integrated water control and oil stabilization system, the injection amount of each additive in the system, and the well shut-in time after all additives are injected, as determined by the method, constitute the driving scheme for heavy oil reservoirs with edge and bottom water.

3. The method for integrated water control and oil stabilization of edge-bottom water thick oil reservoirs according to claim 2, characterized in that: The recovery rate achieved by the aforementioned adjustment method is >15% higher than that before adjustment.

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