A method for optimizing single oil recovery rate by combined flooding of carbon dioxide injection and chemical agents

Abstract

The present invention discloses a method for optimizing the single-shot recovery rate of a combined flooding process using carbon dioxide and chemicals, belonging to the technical field of enhancing oil and gas recovery. The method comprises the following steps: S1: crude oil sampling, mixing the crude oil sample with a variety of chemicals of varying concentrations, and determining the appropriate chemical concentration based on the oil washing rate; S2: determining the injection sequence and injection ratio of the chemicals and carbon dioxide through long core flooding experiments, using the single-shot recovery rate as the optimization metric; S3: establishing a radial three-dimensional model of a single-well flooding process based on the injection sequence and injection ratio of the chemicals and carbon dioxide determined in step S2, and optimizing process parameters through numerical simulation. This method optimizes the injection sequence and injection ratio of carbon dioxide and chemicals for conventional multi-segment composite flooding technology, maximizing the recovery rate of a single-shot carbon dioxide plus composite flooding process. While achieving the same total recovery rate, it reduces the number of repeated operations and saves costs.

Description

Technical Field

[0001] The invention belongs to the technical field of improving oil and gas recovery rate, and relates to a method for optimizing single recovery rate of composite displacement of carbon dioxide injection and chemical agents. Background Art

[0002] In the mid-20th century, gas injection oil recovery technology in my country was still in the stage of mechanism research and laboratory experiments. In recent years, the technology has gradually moved from laboratory experiments to field trials, with an increasing number of oil fields adopting this method to enhance oil recovery, achieving significant results. Research results show that carbon dioxide is more suitable for low-permeability reservoirs than polymers and can increase oil recovery by approximately 5%.

[0003] As early as 1957, alternating gas-water injection (GAWI) was used to enhance oil recovery. Typically, single-phase gas or water flooding processes leave approximately 20%-50% of residual oil in the reservoir. GAWI effectively controls mobility ratios and increases the macroscopic sweep efficiency of the gas, effectively improving oil recovery. A literature review of nearly sixty GAWI applications from 1957 to 1996, including onshore and offshore oilfields, concluded that among numerous offshore GAWI field trials, only a small number achieved success, increasing oil recovery by 5-20% compared to water flooding. GAWI is most commonly used in onshore oilfields (88%), with data showing widespread adoption in countries such as the United States (63%) and Canada (15%). GAWI is commonly employed in tertiary oil recovery (TERR) processes and is now widely adopted in major oilfields worldwide. my country started research on alternating gas-water injection displacement technology relatively late. However, as the proportion of low-permeability oil reservoirs has gradually increased in recent years, gas injection has become one of the main means of developing low-permeability oil reservoirs. Alternating gas-water injection, as an important optimized gas injection method, has been deeply studied in many oil fields.

[0004] Ternary composite flooding leverages the synergistic effects of three displacing agents and the combined effects of chemical agents, significantly improving their oil displacement efficiency and reducing the dosage of chemicals, particularly surfactants. Compared to polymer flooding, it further enhances oil displacement efficiency by expanding the swept volume. Ternary composite flooding technology was first reported in the United States in 1977, and gradually gained international attention. However, the sharp decline in oil prices in the 1990s led most international oil companies to halt research on ternary composite flooding. After 2000, research on ternary composite flooding resumed. my country is already a global leader in this field, with Daqing Oilfield in particular achieving breakthroughs in the application of ternary composite flooding technology.

[0005] As early as the mid-1980s, chemical-based composite flooding technology emerged. This technology leverages the synergistic effects of different chemical agents and their interaction with crude oil active components to significantly reduce surfactant usage and loss. The addition of polymers effectively improves mobility, providing a proven new approach for further enhancing oil recovery and ensuring stable production in the later stages of oilfield development. In 1988, Daqing Oilfield conducted its first research on ASP composite flooding technology, conducting extensive laboratory studies. Successful pilot field trials of ASP flooding were conducted in the western part of the Central District and the central block of the Xingwu District in 1993 and 1994, respectively, demonstrating its effective displacement performance. Expanded field trials were conducted in the western part of the Xinger District in 1996, further validating the ASP flooding's ability to enhance oil recovery, as well as its dynamic characteristics in injection-production capacity and chromatographic separation. In 1997, field trials were conducted in the small-well spacing experimental area of ​​Daqing Oil Production Plant No. 3, using surfactant blends to reduce the dosage of the main surfactant. These experiments yielded significant results in increasing oil production and reducing water loss, demonstrating that ASP flooding improved oil recovery by over 20% (OOIP) compared to water flooding. In 1998, Daqing Oilfield conducted China's first industrial-scale ASP flooding trial, further demonstrating its stable performance and excellent oil displacement under conditions of large well spacing, multiple well groups, and multiple reservoirs. This provided the theoretical basis and practical feasibility for the large-scale implementation of ASP flooding technology in Daqing Oilfield. From 2005 to 2006, large-scale trials were conducted in the Class I reservoirs of the South Fifth Block of Daqing Oilfield. After completing the blank water flooding and pre-polymer slug phases, these trials laid the foundation for the injection of the core system. The ASP system was fully operational in 29 injection wells and 39 production wells in the Daqing Oilfield Production Plant No. 2 pilot brigade. In 2007, a field test of ASP flooding was conducted in the Class II oil layer of the North Area 1 of the Daqing Oilfield Production Plant. The oil wells in the test area blew oil and achieved significant results, further verifying the feasibility of ASP flooding technology in Class II oil layers. Ternary composite flooding is the main direction of the development of new green and efficient chemical additives at this stage.

[0006] Currently, there are numerous trials and applications of binary, ternary, and even multicomponent flooding technologies using CO2 as a carrier. However, these technologies typically employ combinations or repeated slug injections, ultimately achieving limited success. In-depth research is lacking on how to maximize the efficiency of a single slug injection. The combined effects of repeated multi-slug injections obscure the shortcomings of single-shot efficiency, and a lack of in-depth research on the sequencing and ratio of injection volumes leads to increased costs and increased environmental risks.

[0007] From the current situation, multi-component composite flooding has been tested for many years, with the focus on how to improve the recovery rate compared with traditional flooding measures. Multi-component composite displacement technology can produce certain effects through multiple displacements of multiple segments. As long as the recovery rate is improved, the operation will be repeated. As for how to maximize the recovery rate of single-step measures (segment flooding), it has been ignored, resulting in increased costs for multiple operations, more complex distribution of remaining oil in the reservoir, and increased difficulty in later oil production. Summary of the Invention

[0008] The present invention aims to provide a method for optimizing the single-time oil recovery rate (POR) of combined CO2 and chemical flooding. Through experimental simulation, a process for maximizing the POR of combined flooding for specific reservoirs is established, thereby reducing the number of operations required and saving costs. This objective is achieved through the following technical solutions.

[0009] A method for optimizing the single oil recovery rate of carbon dioxide injection and chemical agent composite flooding, characterized by comprising the following steps:

[0010] S1 crude oil sampling, using crude oil samples to mix with a variety of chemical agents of different concentrations, and determining the appropriate concentration of the appropriate chemical agent by the oil washing rate;

[0011] S2 uses a long core flooding experiment to determine the injection sequence and injection ratio of chemicals and carbon dioxide using single recovery as the optimization indicator;

[0012] In step S3, based on the injection sequence and injection ratio of the chemical agent and carbon dioxide determined in step S2, a radial three-dimensional model of a single well displacement is established, and process parameters are optimized through numerical simulation.

[0013] The method for optimizing the single recovery rate of combined carbon dioxide injection and chemical displacement provided by the present invention can maximize the single recovery rate of combined carbon dioxide injection and chemical displacement. Compared with traditional multi-stage plug composite displacement technology, it can reduce the number of repeated operations and save costs while achieving the same total recovery rate.

[0014] Furthermore, the long core flooding experiment described in step S2 is specifically performed as follows:

[0015] S2-1: Short cores retrieved from the target block are spliced ​​into long cores according to a certain arrangement;

[0016] S2-2: After the long core is vacuumed and fully saturated with formation water, it is displaced with degassed crude oil from the surface until no water is produced at the outlet of the long core to establish the irreducible water saturation; the initial and final pump discharges of saturated formation water and the amount of water displaced are recorded;

[0017] S2-3 Long core saturated with formation fluid: Use surface degassed oil to build up pressure to a set value and then maintain constant pressure, raise the temperature to a set value and then maintain constant temperature, and use prepared formation crude oil to displace the surface degassed oil.

[0018] S2-4 carries out a long core displacement experiment at the set pressure and set temperature of step S2-3, adopts different process parameters for displacement until no oil is produced, and calculates the recovery factor under different process parameters.

[0019] Furthermore, in step S2-1, each short core is connected with filter paper to weaken the end effect of the core.

[0020] Furthermore, in step S2-1, the cores are sorted by using the harmonic mean method according to the permeability of each core: the harmonic mean permeability value is compared with the permeability of all cores, and the core with the permeability closest to the harmonic mean permeability is placed first at the outlet; then the harmonic mean permeability of the remaining cores is calculated, and the newly calculated harmonic mean permeability value is compared with all the remaining cores, and the core with the permeability closest to the new harmonic mean permeability value is placed second at the outlet; and so on and so forth to obtain the order of core arrangement.

[0021] Furthermore, the calculation formula of the harmonic mean permeability value is:

[0022]

[0023] Where: L is the total length of the core, in cm;

[0024] K——Harmonic mean permeability of the core, unit 10 -3 μm 2 ;

[0025] L i ——the length of the i-th core, in cm;

[0026] K i ——Permeability of the i-th core, unit 10 -3 μm 2 .

[0027] Furthermore, the different process parameters in step S2-4 include: injecting carbon dioxide or chemicals alone, the order of injecting carbon dioxide and chemicals, and injecting different ratios of carbon dioxide and chemicals.

[0028] Furthermore, in step S3, the process parameters include injection mode, periodic injection volume, injection speed, well shut-in time, displacement cycle, daily production level, and displacement rounds; and the optimization indicators include oil change rate and oil increase.

[0029] This invention provides a method for optimizing the single-shot recovery rate of combined CO2 and chemical flooding. This method optimizes the CO2 and chemical injection sequence and injection rate ratio for traditional multi-stage combined flooding techniques, maximizing the recovery rate of a single CO2 + combined flooding. While maintaining the same total recovery rate, this method reduces the number of repetitive operations and saves costs. This method has been applied to stimulate production in multiple low-porosity and permeability reservoirs in the Northwest region, achieving excellent results. BRIEF DESCRIPTION OF THE DRAWINGS

[0030] Figure 1 It is a flow chart for experimental research on the production increase mechanism of low permeability sandy conglomerate reservoirs.

[0031] Figure 2 It is a graph showing the oil washing rate changing with time.

[0032] Figure 3 This is a schematic diagram of the long core displacement experimental device, where 1-inlet pressure gauge, 2-confining pressure gauge, 3-outlet pressure gauge, 4-back pressure valve, 5-liquid nitrogen cooling system, 6-displacement pump, 7-automatic gas meter.

[0033] Figure 4 This is a graph showing the changes in pore volume multiples and recovery factors for different displacement methods.

[0034] Figure 5 This is a graph showing the changes in pore volume multiples and gas-oil ratio for different displacement methods.

[0035] Figure 6a 、 Figure 6b 、 Figure 6c 、 Figure 6d 、 Figure 6e It is the parameter optimization flow chart.

[0036] Figure 7 This is a production comparison chart of a well in the northwest region before and after the optimization measures were adopted. DETAILED DESCRIPTION

[0037] The following is a clear and complete description of the technical solution of the present invention in conjunction with the accompanying drawings. Obviously, the embodiments described are only part of the embodiments of the present invention, not all of the embodiments. Based on the embodiments of the present invention, all other embodiments obtained by ordinary technicians in this field without making any creative efforts are within the scope of protection of the present invention.

[0038] A method for optimizing the single recovery rate of combined carbon dioxide injection and chemical agent flooding, the overall process is as follows Figure 1 As shown, the following steps are included.

[0039] Step 1: Mix chemicals with crude oil and determine the appropriate chemicals and their concentrations.

[0040] For the crude oil samples in the target area, nano-microemulsion HDKJ-2020 (purchased from Kenyou (Suzhou) Applied Chemicals Co., Ltd., concentration 0.3%) and 2% KCl were used to mix them, and the oil output volume at different times was tested, as shown in Table 1.

[0041] Table 1 Oil volume results of core washing experiment

[0042]

[0043] The oil yield at different times was tested, as shown in Table 2 and Figure 2 shown.

[0044] Table 2 Oil yield results of core washing experiment

[0045]

[0046] From the above results, it can be seen that the oil yield of nano-microemulsion HDKJ-2020 can reach more than 53% after immersion for 6 days, and it was used as a displacement chemical in subsequent experiments.

[0047] Step 2: Laboratory long core simulation to optimize the injection sequence and injection rate ratio of chemicals and carbon dioxide.

[0048] The principle of a long core flooding experiment involves splicing short cores retrieved from a target area into a long core in a specific arrangement. This experiment then simulates the displacement efficiency of actual reservoir fluids during CO2 / chemical flooding in a reservoir. To clarify the displacement mechanism of CO2+chemical fluids in cores, long core flooding experiments with CO2+chemical fluids were conducted to determine the dynamic patterns of key indicators associated with CO2+chemical fluid flooding. The one-dimensional displacement efficiency of CO2+chemical fluids injected into actual reservoir cores was determined for use in the prediction and calibration of CO2+chemical fluid recovery in the field.

[0049] Long core flooding experimental device Figure 3 As shown, it mainly includes an inlet pressure gauge 1, a confining pressure gauge 2, an outlet pressure gauge 3, a back pressure valve 4, a liquid nitrogen cooling system 5, a displacement pump 6 and a fully automatic gas volume meter 7.

[0050] The long core flooding experimental plan is shown in Table 3.

[0051] Table 3 Long core flooding experimental plan

[0052]

[0053] To reduce the end effect of the cores, each short core is connected with filter paper. The cores are sorted based on their permeability using a harmonic mean. The harmonic mean permeability is then compared with the permeabilities of all cores, and the core with the closest permeability is placed first at the outlet. The harmonic mean permeability of the remaining cores is then calculated, and this new value is compared with the remaining (n-1) cores. The core with the closest permeability is placed second at the outlet. This process continues in this order to determine the core arrangement.

[0054] The specific experimental steps are as follows:

[0055] (1) Arrange the short cores in a certain order, insert filter paper between the cores to eliminate the end effect, insert the rubber cartridge, and assemble the long core holder.

[0056] (2) After the core is evacuated and fully saturated with formation water, degassed crude oil is pumped to the core outlet until no water is discharged, thereby establishing irreducible water saturation. The initial and final pump discharges of saturated formation water and the volume of water displaced are recorded.

[0057] (3) Saturate the long core with formation fluid. Use ground degassed oil to build up the pressure to 21.06 MPa and then maintain constant pressure. After raising the oven temperature to 95°C, use the prepared formation crude oil to displace the ground degassed oil. Displace the ground degassed oil until the gas-oil ratio, oil-gas composition and other parameters at the back pressure valve outlet are basically consistent with those of the prepared fluid. Stop the displacement.

[0058] (4) Long core displacement experiments were carried out at a formation pressure of 21.06 MPa and 95°C to test the oil recovery efficiency, including simple chemical flooding, chemical flooding until no oil was produced followed by CO2 flooding, simple CO2 flooding, CO2 flooding without oil production followed by chemical flooding, 0.2HCPV (hydrocarbon pore volume) chemical fluid flooding followed by CO2 flooding, 0.4HCPV chemical fluid flooding followed by CO2 flooding, and 0.6HCPV chemical fluid flooding followed by CO2 flooding until almost no oil was recovered.

[0059] The experimental results are shown in Table 4 and Figure 4 、 Figure 5 shown.

[0060] Table 4 Oil displacement efficiency results of different displacement methods

[0061]

[0062] From Table 4 and Figure 4 、 Figure 5 The following experimental conclusions can be drawn.

[0063] (1) At a formation pressure of 21.14 MPa, the recovery rate of pure CO2 flooding is 68.30%, the recovery rate of chemical flooding after CO2 flooding is 69.40%, the recovery rate of pure chemical flooding is 58.66%, the recovery rate of CO2 flooding after chemical flooding is 67.90%, the recovery rate of 0.2HCPV chemical flooding plus CO2 flooding is 71.91%, the recovery rate of 0.4HCPV chemical flooding plus CO2 flooding is 79.51%, and the recovery rate of 0.6HCPV chemical flooding plus CO2 flooding is 73.87%.

[0064] (2) At a formation pressure of 21.14 MPa, the oil recovery efficiency of CO2 displacement is 9.64% higher than that of pure chemical agents. The gas-oil ratio begins to increase significantly at 0.6 HCPV, making gas channeling more likely.

[0065] (3) Under a formation pressure of 21.14 MPa, when the chemical plug is injected first and then the CO2 is injected for displacement, to a certain extent, the longer the chemical plug is, the later the CO2 gas channeling will occur and the easier it is to stabilize the gas-oil ratio. When the chemical plug is too long, a dominant channel for chemical flooding is established, which will make CO2 gas channeling more likely to a certain extent.

[0066] (4) Under the formation pressure of 21.14 MPa, when the injected chemical plug is too long, the chemical fluid establishes a dominant channel. The injected CO2 gas is easy to channel through the dominant channel and break through more easily, resulting in a smaller effect of CO2, which will affect the contact time between CO2 and crude oil. Late gas injection will result in insufficient contact between CO2 and crude oil, and the gas-water-oil three-phase contact time is short, which weakens the advantage of CO2 miscible drive mechanism in oil recovery and is not conducive to crude oil recovery.

[0067] (5) At a formation pressure of 21.14 MPa, the oil recovery efficiency when injecting a 0.4 HCPV chemical slug was 79.51%, which was 7.60% higher than that of injecting a 0.2 HCPV chemical slug and 5.64% higher than that of injecting a 0.6 HCPV chemical slug. Overall, the 0.4 HCPV chemical slug showed a better oil recovery effect, which not only suppressed CO2 gas channeling but also fully utilized the CO2 miscible flooding effect, resulting in a greater increase in production.

[0068] (6) Based on the actual long core experiment and the fitted fluid model, a long core numerical simulation study was carried out, and the oil displacement mechanism was analyzed. The CO2 near-miscible flooding had a significant viscosity reduction and expansion effect, and the crude oil viscosity could be reduced from 0.53mPa·s to 0.35mPa·s, a reduction of up to 50%. The chemical agent can reduce the oil-water interfacial tension, improve the oil washing efficiency, and significantly improve the core wettability, with the residual oil saturation reduced from 0.35 to 0.2. Combining the chemical agent slug with CO2 displacement can achieve the above viscosity reduction and wettability improvement effects at the same time, which greatly increases the recovery rate in the gas flooding stage.

[0069] Step 3: Process parameter optimization.

[0070] Based on the above experimental results, the 0.4PV chemical agent pre-placement + CO2 flooding process was adopted, the production history curve and PVT parameters and other numerical model parameters required for displacement were fitted, a radial three-dimensional ideal conceptual model of a single well displacement was established, and numerical simulation technology was used to carry out simulation optimization research on key parameters of different displacement methods, including: injection method, cycle injection volume, injection speed, well shut-in time, displacement cycle, daily production level, displacement rounds and other key parameters. The optimal displacement parameters were selected through evaluation indicators such as oil change rate and oil increase. The process parameter optimization process is as follows: Figure 6a 、 Figure 6b 、 Figure 6c 、 Figure 6d 、 Figure 6e shown.

[0071] The optimized process parameters were applied to a well in the northwest region and achieved good results. The oil change rate was greater than 1. The production before and after the optimization measures were used was compared. Figure 7 It can be seen that the daily oil production has been significantly improved after the optimization measures were adopted. After the optimization measures were adopted, the daily decline rate of oil production was reduced from 1.6% to 0.7%, which was effectively slowed down.

[0072] Although the embodiments of the present invention have been shown and described above, it should be understood that the above embodiments are exemplary and should not be construed as limiting the present invention. Those skilled in the art may make changes, modifications, substitutions, and variations to the above embodiments within the scope of the present invention without departing from the principles and intent of the present invention. The scope of protection of the present invention is defined by the claims and their equivalents.

Claims

1. A method for optimizing the single oil recovery rate of combined carbon dioxide injection and chemical agent flooding, characterized in that: The following steps are involved: S1 Crude oil sampling, using crude oil samples to mix with a variety of chemical agents of different concentrations, and determining the appropriate concentration of the appropriate chemical agent by the oil washing rate; S2 uses a long core flooding experiment to determine the injection sequence and injection ratio of chemicals and carbon dioxide using single recovery as the optimization indicator. The specific operation is as follows: S2-1: Short cores retrieved from the target block are spliced ​​into long cores according to a specific arrangement. The cores are sorted based on the permeability of each core using a harmonic mean method: the harmonic mean permeability is compared with the permeability of all cores, and the core with the closest permeability is placed first at the outlet. The harmonic mean permeability of the remaining cores is then calculated, and the newly calculated harmonic mean permeability is compared with all remaining cores. The core with the closest permeability to the new harmonic mean permeability is placed second at the outlet. The order of the cores is determined by analogy. S2-2 After the long core is evacuated and fully saturated with formation water, it is displaced with degassed crude oil from the surface until no water is released from the outlet of the long core to establish the irreducible water saturation; the initial and final pump discharges of saturated formation water and the amount of water displaced are recorded; S2-3 Saturation of formation fluid in long core: Use surface degassed oil to build up pressure to a set value and then maintain constant pressure, raise the temperature to a set value and then maintain constant temperature, and use prepared formation crude oil to displace the surface degassed oil. S2-4 conducting a long core flooding experiment at the set pressure and temperature of step S2-3, using different process parameters for flooding until no oil is produced, and calculating the recovery factor under the different process parameters; S3: Based on the injection sequence and injection ratio of the chemical agent and carbon dioxide determined in step S2, a radial three-dimensional model of a single well displacement is established, and process parameters are optimized through numerical simulation.

2. The method according to claim 1, characterized in that In step S2-1, each short core is connected with filter paper to reduce the end effect of the core.

3. The method according to claim 1, characterized in that The calculation formula of the harmonic mean permeability value is: ， Where: L is the total length of the core, in cm; ——Harmonic mean permeability of the core, unit 10 -3 μm 2 ; L i ——the length of the i-th core, in cm; K i ——Permeability of the i-th core, unit 10 -3 μm 2 .

4. The method according to claim 1, wherein The different process parameters in step S2-4 include: injecting carbon dioxide or chemicals alone, the order of injecting carbon dioxide and chemicals, and injecting different ratios of carbon dioxide and chemicals.

5. The method according to claim 1, wherein In step S3, the process parameters include injection mode, periodic injection volume, injection speed, well shut-in time, displacement cycle, daily production level, and displacement rounds; and the optimization indicators include oil change rate and oil increase.

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