Emulsified viscosity reducer and use thereof

Abstract

The application provides an emulsified viscosity reducer and application thereof. The emulsified viscosity reducer comprises sodium tripolyphosphate, sodium nonylphenol polyoxyethylene ether sulfate, soapberry saponin, coconut oil diethanolamine and water.

Description

Technical Field

[0001] This invention relates to the field of heavy oil development, and particularly to an emulsifying viscosity reducer. Background Technology

[0002] In the field of heavy oil waterflooding, the use of viscosity reducers is consistently applied throughout the entire lifecycle of heavy oil development. Heavy oil waterflooding using viscosity reducers shows significant production effects in the early stages, but in the mid-stages, it cannot effectively rely on natural energy for displacement and also requires replenishment of the energy lost in the heavy oil formation.

[0003] Benefiting from its advantageous gas supply, China's heavy oil CO2 displacement technology has developed rapidly and achieved remarkable results. It boasts advantages such as strong solubility, viscosity reduction, and formation energy replenishment, effectively improving the recovery rate of heavy oil reservoirs. Currently, after years of CO2 displacement for heavy oil production enhancement, heavy oil reservoirs in my country have generally entered the mid-stage of production, resulting in severe CO2 channeling and significantly hindering further development. Therefore, effectively controlling CO2 channeling and high water cut in heavy oil reservoirs is a pressing issue requiring research. Currently, there are two main methods for controlling CO2 and water channeling in heavy oil:

[0004] Firstly, adjusting the mobility ratio through chemical flooding and blocking high-permeability layers can effectively improve the problems of CO2 and water channeling in heavy oil. Injecting emulsifiers into heavy oil can reduce its viscosity, and the resulting emulsion can block CO2 channeling pathways, thereby improving recovery rates. Moreover, compared to water, emulsion viscosity reducer solutions are more likely to form a stable foam system with CO2. However, simply injecting emulsifiers into heavy oil reservoirs cannot propel them into the deeper reservoir layers; most of them accumulate near the wellbore. Furthermore, simply injecting emulsifiers cannot solve problems such as formation energy depletion.

[0005] Secondly, after the early water-driven and mid-term CO2-driven processes in heavy oil reservoirs, foam flooding can be used in the later stages to block gas and water channeling and adjust the non-uniform advance of the gas and liquid displacement profile. However, foam stability is not strong enough. Therefore, overall, for heavy oil reservoirs developed in the mid-term stage, how to effectively overcome the production problems of CO2 gas channeling and high water content and water channeling is an urgent technical problem to be solved. Summary of the Invention

[0006] One aspect of the present invention provides an emulsifying viscosity reducer comprising sodium tripolyphosphate, sodium nonylphenol polyoxyethylene ether sulfate, soapberry saponins, coconut oil diethanolamine, and water.

[0007] In one specific embodiment, the sodium tripolyphosphate content is 3% to 4%, based on 100% of the total mass of the emulsified viscosity reducer.

[0008] In one specific embodiment, the content of sodium nonylphenol polyoxyethylene ether sulfate is 10% to 12%, based on 100% of the total mass of the emulsified viscosity reducer.

[0009] In one specific embodiment, the content of Sapindus saponins is 5% to 6%, based on 100% of the total mass of the emulsifying viscosity reducer.

[0010] In one specific embodiment, the content of coconut oil diethanolamine is 3% to 5%, based on 100% of the total mass of the emulsified viscosity reducer.

[0011] In one specific embodiment, the water content is 73% to 79%, calculated as 100% by the total mass of the emulsified viscosity reducer.

[0012] The second aspect of the present invention provides the application of the emulsified viscosity reducer according to any one of the present inventions in the viscosity reduction of heavy oil.

[0013] The third invention provides a method for composite displacement of heavy oil, the method comprising alternately injecting an emulsifying viscosity reducer as described in any one of the inventions and CO2 into the target oil reservoir.

[0014] In one specific embodiment, the volume ratio of the emulsified viscosity reducer to the CO2 injected into the target oil reservoir is 1:1.

[0015] In one specific embodiment, the injection volume ratio of the emulsifying viscosity reducer to the CO2 per unit time is 1:1.

[0016] In one specific implementation, the formula for calculating the total ground volume of the injected CO2 is shown in Equation 1):

[0017]

[0018] Where V0 is the total surface volume of the injected CO2, T is the target reservoir temperature, P is the target reservoir pressure, and e is a constant.

[0019] In one specific embodiment, the formula for calculating the total ground volume injected with the emulsified viscosity reducer is shown in Equation 2):

[0020] m = 0.1575e 0.003614(0.1-P) 2)

[0021] Where m is the total mass of the injected emulsified viscosity reducer, P is the target reservoir pressure, and e is a constant.

[0022] In one specific embodiment, the injection pressure of the emulsified viscosity reducer and the CO2 is independently 1.5 times the target reservoir pressure.

[0023] The beneficial effects of this invention are:

[0024] (1) The emulsified viscosity reducer provided by the present invention has the characteristics of high temperature resistance and high salt resistance. It can be used not only in ordinary heavy oil, but also in heavy oil reservoirs with high temperature and high salinity.

[0025] (2) Compared with the single emulsifier viscosity reduction displacement technology, the displacement of heavy oil by combining viscosity reduction agent and CO2 can significantly reduce the viscosity of heavy oil and maintain good stability. In addition, CO2 displacement can play a role in replenishing formation energy.

[0026] (3) Compared with CO2-driven heavy oil, the addition of emulsified viscosity reducer solution can effectively increase the solubility of CO2, thereby blocking the gas channel and solving the gas channeling problem. Attached Figure Description

[0027] Figure 1 The data shows the daily oil production and water cut of a heavy oil reservoir in Block A from September 1998 to April 2020. Detailed Implementation

[0028] The present invention will be further described below with reference to the embodiments. However, the embodiments of the present invention are merely illustrative examples and should not be construed as limiting the present invention under any circumstances.

[0029] Example 1

[0030] Add 3.5g of sodium tripolyphosphate (Na5P3O) 10 ), 11g nonylphenol polyoxyethylene ether sodium sulfate (C 30 H 46 O·OSO3Na + ), 5.5g Sapindus mukorossi saponins, 4g coconut oil diethanolamine (C4H) 11 NO2) and 76g of water are mixed evenly to obtain an emulsified viscosity reducer.

[0031] Example 2

[0032] Add 3g of sodium tripolyphosphate (Na5P3O) 10 ), 10g nonylphenol polyoxyethylene ether sodium sulfate (C 30 H 46 O·OSO3Na + ), 5g Sapindus mukorossi saponins, 3g coconut oil diethanolamine (C4H) 11 NO2) and 79g of water are mixed evenly to obtain an emulsified viscosity reducer.

[0033] Example 3

[0034] Add 4g of sodium tripolyphosphate (Na5P3O) 10), 12g nonylphenol polyoxyethylene ether sodium sulfate (C 30 H 46 O·OSO3Na + ), 6g Sapindus mukorossi saponins, 5g coconut oil diethanolamine (C4H) 11 NO2) and 73g of water are mixed evenly to obtain an emulsified viscosity reducer.

[0035] Comparative Example 1

[0036] Add 3.5g of sodium tripolyphosphate (Na5P3O) 10 ), 11g nonylphenol polyoxyethylene ether sodium sulfate (C 30 H 46 O·OSO3Na + 5.5g ethyl acrylate (C5H8O2), 4g coconut oil diethanolamine (C4H 11 NO2) and 76g of water are mixed evenly to obtain an emulsified viscosity reducer.

[0037] Comparative Example 2

[0038] Add 3.5g of sodium tripolyphosphate (Na5P3O) 10 ), 11g nonylphenol polyoxyethylene ether sodium sulfate (C 30 H 46 O·OSO3Na + 5.5g rhamnose (C6H) 12 O5, CAS No. 6155-35-7), 4g coconut oil diethanolamine (C4H 11 NO2) and 76g of water are mixed evenly to obtain an emulsified viscosity reducer.

[0039] Comparative Example 3

[0040] Add 3.5g of sodium tripolyphosphate (Na5P3O) 10 ), 11g nonylphenol polyoxyethylene ether sodium sulfate (C 30 H 46 O·OSO3Na + ), 5.5g trimethylglycine (C5H) 11 NO2), 4g coconut oil diethanolamine (C4H) 11 NO2) and 76g of water are mixed evenly to obtain an emulsified viscosity reducer.

[0041] Comparative Example 4

[0042] Add 3.5g of sodium tripolyphosphate (Na5P3O) 10 ), 11g nonylphenol polyoxyethylene ether sodium sulfate (C 30 H 46 O·OSO3Na + ), 5.5g sodium dodecylbenzenesulfonate (C18 H 29 SO3Na), 4g coconut oil diethanolamine (C4H) 11 NO2) and 76g of water are mixed evenly to obtain an emulsified viscosity reducer.

[0043] Comparative Example 5

[0044] Add 3.5g of sodium tripolyphosphate (Na5P3O) 10 ), 11g nonylphenol polyoxyethylene ether sodium sulfate (C 30 H 46 O·OSO3Na + ), 5.5g polyacrylamide ((C3H5NO)n, where n=140-281690), 4g coconut oil diethanolamine (C4H 11 NO2) and 76g of water are mixed evenly to obtain an emulsified viscosity reducer.

[0045] Performance testing of emulsified viscosity reducers

[0046] 1. Viscosity reduction

[0047] The emulsified viscosity reducers prepared in Examples 1 to 3 and the emulsified viscosity reducers prepared in Comparative Examples 1 to 5 were respectively prepared into emulsified viscosity reducer aqueous solutions with a content of 0.2% by water.

[0048] (1) Use a crude oil electro-dehydration device to electro-dehydrate the crude oil obtained on site to obtain dehydrated and degassed crude oil;

[0049] (2) Add crude oil to the PY-I type piston high-pressure sampler;

[0050] (3) At a temperature of 100℃ and a pressure of 0.1MPa, each emulsified viscosity reducer aqueous solution is added to the high-pressure sampler at a mass ratio of 1:10 with crude oil. After the emulsified viscosity reducer aqueous solution in the high-pressure sampler is fully mixed with crude oil, viscosity-reducing oil is obtained.

[0051] (4) Measure the viscosity of the mixture: 4-1) Adjust the CHY-II type falling ball viscometer to 100℃; 4-2) Pump the crude oil or viscosity-reducing oil in the high-pressure sampler into the CHY-II type falling ball viscometer through the plunger pump; 4-3) Measure the initial viscosity of the crude oil or the viscosity of the viscosity-reducing oil, measure 3 times and take the average value.

[0052] (5) Calculate the viscosity reduction rate, and the results are shown in Table 1.

[0053] Among them, viscosity reduction rate refers to the percentage decrease in viscosity of crude oil after the addition of emulsifying viscosity reducer.

[0054] The calculation formula is as follows:

[0055]

[0056] Where: X1—initial viscosity of crude oil, mPa·s;

[0057] X2 — Viscosity of the emulsion-reducing oil, mPa·s.

[0058] 2. Resistance Factor

[0059] The drag factor is the ratio of the pressure difference established at both ends of the core by the displacement system to the pressure difference during water drive.

[0060] Prepare a 0.2 wt% emulsified viscosity reducer solution using water (i.e., the emulsified viscosity reducer content is 0.2%).

[0061] 1) Fill with 100 to 120 mesh quartz sand Sand-filled pipe A is used to simulate a heavy oil reservoir. The dry weight of the sand-filled pipe filled with quartz sand is weighed, then vacuumed, saturated with water, and the wet weight is weighed. The porosity is calculated based on the dry and wet weights.

[0062] 2) Inject clean water into the sand-filling pipe A at a rate of 1 mL / min, record the pressure at the injection end and the pressure at the outlet end of the sand-filling pipe when it is stable, and then calculate the pressure difference P1 between the injection end and the outlet end, in MPa.

[0063] 3) Inject the emulsified viscosity reducer solution into the sand-filled tube A at a rate of 1 mL / min. During the injection process, record the pressure at the injection end and the pressure at the outlet end of the sand-filled tube when 1 PV of emulsified viscosity reducer solution is injected. Then calculate the pressure difference P2 between the injection end and the outlet end, in MPa.

[0064] 3) Calculate the drag factor R based on P1 and P2. The results are shown in Table 1.

[0065] The calculation formula is as follows:

[0066]

[0067] Table 1

[0068] Example Viscosity reduction Resistance factor Example 1 98.15％ 42.5 Example 2 98.26％ 41.8 Example 3 98.12％ 41.2 Comparative Example 1 70.68％ 32.1 Comparative Example 2 79.76％ 35.5 Comparative Example 3 83.79％ 36.3 Comparative Example 4 94.25％ 28.6 Comparative Example 5 89.68％ 38.2

[0069] As can be seen from the data in Table 1, the emulsified viscosity reducers of Examples 1 to 3 are superior to the emulsified viscosity reducers of Comparative Examples 1 to 5.

[0070] Example 4

[0071] A certain block A contains heavy oil reservoirs with geological reserves of 3.529 million tons, a burial depth of 2200 to 3100 meters, and an oil-bearing area of ​​0.69 km². 2The average effective thickness is 22.6m, the geothermal gradient is 2.42℃ / 100m, the pressure gradient is 1.02MPa / 100m, the average permeability is 300mD, the average effective porosity is 24.7%, the crude oil viscosity is 286-324mPa·s, the average daily fluid production in the target well section is 79.731t, the daily oil production is 26.2t, and the overall water cut is 67.14%.

[0072] Water flooding began in August 2008 and initially showed good results, but in the later stages, oil production gradually decreased and water content gradually increased.

[0073] In January 2015, heavy oil was displaced by combining carbon dioxide with the emulsified viscosity reducer of this invention. The specific operation is as follows:

[0074] 1) Determine the ground volume V0 of the injected CO2 (unit: m³) 3 ):

[0075] The density function of CO2 is given by the following formula:

[0076]

[0077] In formula (1), ρ is the density of CO2 (unit: kg / m³). 3 P is pressure (unit: MPa), and e is a constant (i.e., the natural logarithm).

[0078] The mass function relationship is given as follows: m=ρv——(2)

[0079] Based on the mass function relationship (2), we know that: ρ0V0=ρV——(3)

[0080] Based on the functional relationship (3), we know that:

[0081] Given parameters: the density of CO2 at ground level of 25℃ is ρ0 = 1.80541 kg / m³, and the volume of CO2 in the target oil reservoir is set to V = 0.15PV. Then, substitute formula (1), V, and ρ0 into formula (4) to obtain the ground volume V0 (unit: m³) of the total amount of CO2 to be injected. 3 The functional relationship is as follows;

[0082]

[0083] Given parameters: surface temperature T0 = 25℃, surface pressure P0 = 0.1MPa, target reservoir temperature T = T0 + geothermal gradient × burial depth (unit: ℃), target reservoir pressure P = P0 + pressure gradient × burial depth (unit: MPa).

[0084] Therefore, based on the above formula (5) and the above known parameters, the ground volume V0 of the total CO2 to be injected is calculated to be 240,000 (unit: kg / m³). 3 ).

[0085] 2) The formula given in "Reservoir Physics" determines the mass of the injected emulsified viscosity reducer:

[0086] m=ρ1Ye c1(P0-P) ——(6)

[0087] In formula (6), m is the total mass of the injected emulsified viscosity reducer (unit: kg), and the density of the emulsified viscosity reducer on the ground is ρ1 = 1050 kg / m³. 3 The volume of the emulsified viscosity reducer in the target reservoir is set to Y = 0.15 PV, and the compressibility coefficient of the emulsified viscosity reducer is c. l =3.614×10 -3 (Unit: MPa) -1 The surface pressure is P0 = 0.1 MPa, where P is the pressure of the target oil reservoir (unit: MPa) and e is a constant (i.e., the natural logarithm).

[0088] Based on the above formula (6) and the above known parameters, the mass formula for injecting the emulsified viscosity reducer is determined as follows:

[0089] m = 0.1575e 0.003614(0.1-P) ——(7)

[0090] Known parameters: Target reservoir pressure: The pressure of the target reservoir is P = P0 + pressure gradient × burial depth (unit: MPa), the surface pressure is P0 = 0.1 MPa, and e is a constant (i.e., natural logarithm).

[0091] Therefore, based on the above formula (7) and the above known parameters, the total mass of the emulsified viscosity reducer to be injected is calculated to be 2000t.

[0092] 3) The injection method provided by this invention is an equal-volume gas-liquid slug alternating injection scheme. The specific parameters are: the injection volume ratio of CO2 gas to emulsion viscosity reducer per unit time is 1:1, the injection pressure is 1.5 times the target reservoir pressure, that is, the injection pressure is 45 MPa, and the slug duration is 15 days.

[0093] This technical solution was used from September 2012 to April 2020, a total of 2765 days of production.

[0094] Figure 1 The data shows the daily oil production and water cut of a heavy oil reservoir in Block A from September 1998 to April 2020. Calculations show that during the entire implementation phase of this technical solution, a cumulative increase of 436,000 tons of oil was achieved.

[0095] While the present invention has been described with reference to specific embodiments, those skilled in the art will understand that various changes can be made without departing from the true spirit and scope of the invention. Furthermore, numerous modifications can be made to the subject, spirit, and scope of the invention to suit specific situations, materials, material compositions, and methods. All such modifications are included within the scope of the claims of the present invention.

Claims

1. An emulsifying viscosity reducer comprising sodium tripolyphosphate, sodium nonylphenol polyoxyethylene ether sulfate, soapberry saponins, coconut oil diethanolamine, and water; Based on the total mass of the emulsifying viscosity reducer as 100%, the content of sodium tripolyphosphate is 3% to 4%, the content of sodium nonylphenol polyoxyethylene ether sulfate is 10% to 12%, the content of soapberry saponin is 5% to 6%, and the content of coconut oil diethanolamine is 3% to 5%.

2. The emulsifying viscosity reducer according to claim 1, characterized in that, The water content is 73% to 79%, calculated as 100% by the total mass of the emulsified viscosity reducer.

3. The application of the emulsifying viscosity reducer according to claim 1 or 2 in the viscosity reduction of heavy oil.

4. A method for displacing heavy oil using a composite method, the method comprising alternately injecting an emulsified viscosity reducer as described in claim 1 or 2 with CO2 into a target oil reservoir.

5. The method according to claim 4, characterized in that, The volume ratio of the emulsified viscosity reducer to the CO2 injected into the target oil reservoir is 1:

1.

6. The method according to claim 4, characterized in that, The injection volume ratio of the emulsified viscosity reducer to the CO2 per unit time is 1:

1.

7. The method according to any one of claims 4 to 6, characterized in that, The injection pressure of the emulsified viscosity reducer and the CO2 is independently 1.5 times the reservoir pressure of the target oil reservoir.

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