Nuclear magnetic resonance-based shale oil energy supplement new mode indoor experiment evaluation method

Abstract

The invention belongs to the technical field of oil and gas field development, and discloses a nuclear magnetic resonance-based shale oil energy supplement new mode indoor experiment evaluation method, which comprises the following steps: S1, rock sample pretreatment; s2, vacuumizing and pressurizing the rock sample to saturate heavy water; s3, displacement of saturated heavy water by kerosene; s4, displacing kerosene with in-situ crude oil; s5, simulating depletion type development, and calculating the crude oil recovery rate of the depletion type development rock sample; s6, a chemical agent is injected for temporary plugging; and S7, simulating CO2 injection and nano-agent energy supplement development under different injection pressures and different throughput rounds, and calculating the crude oil recovery rate of the rock sample after energy supplement under different injection pressures and different throughput rounds. According to the indoor evaluation experiment method for the novel energy supplement development mode under chemical agent plugging, nano agent flooding and CO2 huff and puff, the problems of CO2 injection and liquid channeling and the problem that the oil yield is rapidly decreased cycle by cycle in the single CO2 injection huff and puff or gas-water alternate injection stage can be solved, mine field practice is guided, and efficient shale oil development is achieved.

Description

Technical Field

[0001] This invention belongs to the field of oil and gas field development technology, specifically relating to an indoor experimental evaluation method for a new shale oil energy replenishment method based on nuclear magnetic resonance. Background Technology

[0002] Water injection is a primary method for enhancing oil recovery in conventional reservoirs through energy replenishment, but it cannot be applied to shale reservoirs. This is mainly because clay in shale reservoirs swells upon contact with water, resulting in high heterogeneity, low waterflood sweep efficiency, and poor waterflood injection capacity due to low permeability. Existing laboratory and field test results indicate that CO2 injection is a more effective method for enhancing oil recovery in shale reservoirs through energy replenishment.

[0003] First, CO2 injection can significantly reduce the interfacial tension of reservoir fluids and the viscosity of crude oil. Second, CO2 can dissolve carbonates near the wellbore, leading to increased permeability in the wellbore area. Finally, when the injection temperature and pressure reach certain conditions, CO2 can achieve miscibility with formation fluids, significantly improving the recovery rate of shale oil reservoirs. Compared with N2 and CH4, CO2 is more likely to achieve miscibility pressure with formation fluids. Because CO2 has a stronger solubility in formation water under miscible conditions than under immiscible conditions, it is less likely to form scale and clog formation pores. In addition, as a greenhouse gas, CO2 injection into the formation has a good effect on greenhouse gas storage and mitigating the global greenhouse effect.

[0004] However, shale oil reservoir development requires volumetric fracturing, which creates a large-scale fracture system. CO2 can easily migrate through these fractures, resulting in low sweep efficiency and insufficient penetration into the shale oil reservoir matrix. Consequently, CO2 replenishment is ineffective, leaving a large amount of crude oil remaining in the shale oil reservoir matrix. Furthermore, relying solely on CO2 huff and puff or alternating gas-water injection cannot achieve continuous replenishment, leading to a rapid decline in oil production over each cycle, making it an unsustainable development approach.

[0005] Currently, shale oil regeneration methods mainly focus on CO2 injection huff and puff and alternating gas-water injection. Huff and puff + displacement regeneration technologies are less common and have several problems. For example, Chinese patent CN111749658A discloses a CO2 huff and puff oil recovery method and device, which improves oil recovery through CO2 huff and puff operations on multiple oil wells. However, it only considers a single CO2 injection huff and puff mode and does not consider a displacement + huff and puff mode, thus having certain limitations. Chinese patent CN114894832A discloses an experimental device for evaluating the effect of CO2 injection electromagnetic heating-assisted energy enhancement and production increase in shale oil. The method and approach analyzed the effect of CO2 huff and puff on improving oil recovery at different electromagnetic heating temperatures, but it only considered the huff and puff mode and did not consider the displacement + huff and puff mode, which has certain limitations. Chinese patent CN116733427A discloses a method for improving the oil recovery of shale oil well groups by using carbon dioxide huff and puff + displacement. It utilizes the dual effects of carbon dioxide huff and puff and carbon dioxide displacement to expand the scope of carbon dioxide's effect and improve the oil recovery of shale oil. However, it only considers the single CO2 huff and puff and displacement mode and does not consider the development mode of multi-media huff and puff and displacement combined, which still has certain limitations.

[0006] Therefore, there is an urgent need for a replacement technology that combines chemical plugging, nano-flooding, and CO2 huff and puff, which can flexibly establish displacement relationships in multiple ways, make full use of percolation, improve displacement and huff and puff effects, and increase the recovery rate. Summary of the Invention

[0007] This invention aims to address the technical problems existing in the background art by providing a novel indoor experimental evaluation method for shale oil refueling based on nuclear magnetic resonance. It proposes an indoor evaluation experimental method for a new refueling development approach under the "chemical plugging + nano-pumping + CO2 huff and puff" model, which can solve the problems of CO2 injection and liquid cross-flow, as well as the problem of rapid decline in oil production cycle by cycle in the single CO2 huff and puff or gas-water alternating injection stage. This provides guidance for field practice and enables efficient shale oil development.

[0008] To achieve the above technical objectives, the present invention adopts the following technical solution:

[0009] A novel indoor experimental evaluation method for shale oil refueling based on nuclear magnetic resonance, the method comprising the following steps:

[0010] Step S1. Rock sample pretreatment;

[0011] Step S2. Place the rock sample into the piston container, evacuate the rock sample and pressurize it with saturated heavy water;

[0012] Step S3. Displace the rock sample saturated with heavy water with kerosene until it is in a bound water state;

[0013] Step S4. Under simulated formation conditions, replace kerosene with formation crude oil to obtain the original oil saturation of the rock sample and measure its nuclear magnetic resonance T2 spectrum;

[0014] Step S5. Simulate depletion-type development, measure the nuclear magnetic resonance T2 spectrum, and calculate the oil recovery rate of the rock sample under depletion-type development;

[0015] Step S6. After depletion-induced development, inject chemical agents to temporarily plug the fracture ends of the rock sample;

[0016] Step S7. Simulate CO2 and nano-agent injection for energy replenishment under different injection pressures and different huff and puff cycles, measure nuclear magnetic resonance T2 spectra, and calculate the oil recovery rate of rock samples after energy replenishment under different injection pressures and huff and puff cycles.

[0017] Further, step S1 specifically includes:

[0018] Step S11: Wash the oil, dry, weigh the rock sample, and measure the basic physical properties of the rock sample;

[0019] The basic physical properties of the rock sample include rock sample size, porosity φ, and permeability K, wherein the rock sample size includes the length L and diameter d of the rock sample;

[0020] Step S12: Perform wire cutting on the rock sample to prepare a rock sample simulating the presence of pressure fractures.

[0021] Furthermore, in step S12, the wire cutting position is at the center line of the circular end face of the rock sample, and the wire cutting length is half the length of the rock sample.

[0022] Furthermore, in step S2, pressurized saturated heavy water is applied until the rock sample has a water saturation of ≥98%.

[0023] Furthermore, step S2 specifically includes:

[0024] Step S21: Place the rock sample in a piston container with a volume of 1000ml and a pressure resistance of 50MPa, and use a vacuum pump to evacuate the rock sample in the piston container for 4-6 hours;

[0025] Step S22: Inject heavy water into the intermediate container until the heavy water fills the entire piston container, and increase the pressure of the heavy water in the piston container to 20MPa, saturating for 72 hours;

[0026] Step S23: After 72 hours of saturation, measure the weight m2 of the rock sample and calculate the water saturation of the rock sample. If the water saturation of the rock sample is less than 98%, pressurize and saturate it with heavy water again.

[0027] The formula for calculating water saturation is as follows:

[0028]

[0029] In the above formula:

[0030] S w —Water saturation of rock sample, %;

[0031] m1—dry weight of rock sample, g;

[0032] m2 — Weight of rock sample after saturation with heavy water, in grams;

[0033] ρ w —Density of heavy water, g / cm³ 3 ;

[0034] V P —Pore volume of rock sample, cm³ 3 .

[0035] Furthermore, step S3 specifically includes:

[0036] Step S31: Place the rock sample in the core holder and heat it to the formation temperature. Displace the heavy water with kerosene under the conditions of a confining pressure of 5 MPa, an inlet pressure of 2.5 MPa, and an outlet pressure of atmospheric pressure until the nuclear magnetic resonance T2 spectrum curve no longer changes with time.

[0037] Step S32: Measure the weight of the rock sample after displacement and calculate the original oil saturation and bound water saturation of the rock sample.

[0038] Furthermore, in step S32:

[0039] The formula for calculating the initial oil saturation is:

[0040]

[0041] In the above formula:

[0042] S oi —Original oil saturation of the rock sample, %;

[0043] m2—Weight of the rock sample after saturation with heavy water, in grams;

[0044] m3 — Weight of rock sample after kerosene flooding, in grams;

[0045] ρ w —Density of heavy water, g / cm³ 3 ;

[0046] ρ o1 — Density of kerosene, g / cm³ 3 ;

[0047] V P —Pore volume of rock sample, cm³ 3 ;

[0048] The formula for calculating the bound water saturation is:

[0049] S wc =1-S oi

[0050] In the above formula:

[0051] S wc —Bound water saturation of rock sample, %;

[0052] S oi —Oil saturation of rock sample, %.

[0053] Furthermore, step S4 specifically includes:

[0054] Step S41: Place the rock sample in the nuclear magnetic resonance holder, control the confining pressure of the rock sample with a hand pump, then control the pressure at the outlet end of the rock sample with a back pressure pump, and at the same time control the temperature of the rock sample with a heating device to make the pressure and temperature conditions of the rock sample consistent with the original formation conditions.

[0055] Step S42: Under simulated formation conditions, use formation crude oil to displace kerosene and record the oil production V at the rock sample outlet. o Water production V at the rock sample outlet w Simultaneously, the nuclear magnetic resonance T2 spectrum was tested until the nuclear magnetic resonance T2 spectrum curve no longer changed with time, at which point the displacement was terminated.

[0056] Step S43: Calculate the original oil saturation of the rock sample based on the oil production at the outlet end of the rock sample and the water production at the outlet end of the rock sample, and obtain the relationship between the original oil saturation of the rock sample and the nuclear magnetic resonance T2 spectrum based on the calculation results.

[0057] Furthermore, in step S43, the formula for calculating the original oil saturation of the rock sample is:

[0058]

[0059] In the above formula:

[0060] S o —Original oil saturation of the rock sample, %;

[0061] S oi —Oil saturation of rock sample, %;

[0062] V w —Water production at the rock sample outlet, cm 3 ;

[0063] V P —Pore volume of rock sample, cm³ 3 .

[0064] Furthermore, step S5 specifically includes:

[0065] Step S51: Based on the formation pressure produced on-site, calculate the pressure deficit conditions under laboratory conditions using the similarity principle;

[0066] Step S52: Under simulated laboratory formation conditions, depletion development is carried out to the corresponding pressure conditions to simulate different formation energy depletion states;

[0067] Step S53: During the simulation, monitor the rock sample pressure. When the rock sample pressure drops to the bubble point pressure, stop the depletion development, record the oil production at the outlet, and test the nuclear magnetic resonance T2 spectrum of the rock sample to calculate the oil recovery rate of the rock sample developed by elastic energy during the depletion development process.

[0068] Furthermore, in step S53, the oil recovery rate E of the rock sample developed using elastic energy during the depletion development process... d The calculation formula is:

[0069]

[0070] In the above formula:

[0071] E d —Simulated depletion-induced oil recovery rate of rock samples, %;

[0072] T 2,max —Maximum relaxation time on nuclear magnetic resonance (NMR), ms;

[0073] T 2,min —Minimum relaxation time of nuclear magnetic resonance, ms;

[0074] M i,d —The nuclear magnetic resonance amplitude value corresponding to the relaxation time when the rock sample pressure equals the bubble point pressure, which is dimensionless;

[0075] M i,i —The nuclear magnetic resonance amplitude value corresponding to the relaxation time in the original state, dimensionless;

[0076] T 2i,d —Relaxation time when rock sample pressure equals bubble point pressure, in milliseconds;

[0077] T 2i,i — Relaxation time in the original state, ms.

[0078] Furthermore, step S7 specifically includes:

[0079] Step S71: Simulate a single round of refueling development:

[0080] Simulating the minimum miscibility pressure of "CO2-crude oil" and the single-round CO2 injection and nano-agent supplementation development, measuring the nuclear magnetic resonance T2 spectrum, and calculating the minimum miscibility pressure of "CO2-crude oil" and the oil recovery rate of the production rock sample after a single round of supplementation; specifically including:

[0081] Step S711: Based on the experimental rock sample after temporary plugging, CO2 is injected into the simulated depletion development and production end, and nanoparticles are injected into the other end. At the same time, the rock sample pressure is monitored until the rock sample pressure reaches the minimum miscibility pressure of "CO2-crude oil". The rock sample is then sealed for a period of time, and the nuclear magnetic resonance T2 spectrum during the sealing process is tested.

[0082] Step S712: After the well is shut down, open the CO2 injection end to simulate production and measure the nuclear magnetic resonance T2 spectrum curve. After the T2 spectrum curve no longer changes, combine it with the nuclear magnetic resonance T2 spectrum curve of the rock sample in its original state to calculate the oil recovery rate of the rock sample under the simulated single round of "chemical plugging + nano-pumping + CO2 huff and puff".

[0083] Step S72: Simulate multiple rounds of energy replenishment development, specifically including:

[0084] Based on the experimental rock sample in step S712, under the minimum miscibility pressure of "CO2-crude oil", CO2 and nano-agent were repeatedly injected in multiple rounds. After the well was shut down for a period of time, the CO2 injection end was opened to simulate production. The nuclear magnetic resonance T2 curve was measured. Combined with the nuclear magnetic resonance T2 spectrum curve of the rock sample in its original state, the rock sample simulated CO2 huff and puff + nano-agent drive for multiple rounds of energy replenishment to produce crude oil recovery rate.

[0085] Step S73: Select parallel rock samples and repeat the rock sample experiment according to steps S1-S6. Based on the parallel experimental rock samples, repeat the experiment in steps S71-S72 under the condition of changing the CO2 injection pressure P1 to obtain the oil recovery rate of the rock samples produced after replenishment under different injection pressures and huff and puff cycles. Stop the experiment when the oil recovery rate no longer changes and calculate the total recovery rate of the rock samples.

[0086] Furthermore, in step S712, the oil recovery rate E of the produced rock sample after a single round of energy replenishment is... i The calculation formula is:

[0087]

[0088] In the above formula:

[0089] E i —Raw oil yield from a single round of refueling of a rock sample, %;

[0090] T 2,max —Maximum relaxation time on nuclear magnetic resonance (NMR), ms;

[0091] T2,min —Minimum relaxation time of nuclear magnetic resonance, ms;

[0092] m i,d —The NMR amplitude value corresponding to the relaxation time in the original state, dimensionless;

[0093] m i,i —NMR amplitude value corresponding to the relaxation time after energy replenishment, dimensionless;

[0094] T 2i,d — Relaxation time in the initial state, in milliseconds;

[0095] T 2i,i —State relaxation time after energy replenishment development, ms.

[0096] Furthermore, in step S72, the oil recovery rate E of the produced rock sample after multiple rounds of energy replenishment... i' The calculation formula is:

[0097]

[0098] In the above formula:

[0099] E i' —Oil recovery rate of produced rock samples after multiple rounds of refueling, %;

[0100] T 2,max —Maximum relaxation time on nuclear magnetic resonance (NMR), ms;

[0101] T 2,min —Minimum relaxation time of nuclear magnetic resonance, ms;

[0102] m i,d —The NMR amplitude value corresponding to the relaxation time in the original state, dimensionless;

[0103] m i,i —NMR amplitude value corresponding to the relaxation time after energy replenishment, dimensionless;

[0104] T 2i,d — Relaxation time in the initial state, in milliseconds;

[0105] T 2i,i —State relaxation time after energy replenishment development, ms.

[0106] Furthermore, in step S7, the CO2 injection pressure P1 is set to 0.5-2 MMP, where MMP is the minimum miscibility pressure between CO2 and crude oil.

[0107] Furthermore, the following steps are included after step S7:

[0108] Step S8. Based on the experimental results, plot the relationship curves between different injection pressures, different throughput cycles, and the oil recovery rate of the rock sample.

[0109] Compared with the prior art, the beneficial effects of the present invention are:

[0110] (1) The indoor experimental evaluation method of the new shale oil energy replenishment method based on nuclear magnetic resonance provided by the present invention proposes for the first time a "chemical plugging agent + nano-displacement agent + CO2 huff and puff" composite huff and puff energy replenishment mode. Among them, the chemical plugging agent can effectively prevent CO2 crossflow during the huff and puff process after fracturing and development of shale oil reservoirs, and the addition of nano-displacement agent can enhance the permeation and adsorption effect and expand the oil displacement area. In addition, the diffusion and mass transfer effect of CO2 can improve the overall composite huff and puff to improve the recovery rate. Furthermore, the indoor optimization of the above composite huff and puff energy replenishment mode can be carried out by nuclear magnetic resonance technology. The method is simple and easy to operate, providing basic support and theoretical reference for supporting the efficient development of shale oil.

[0111] (2) The method of the present invention uses chemical agents to temporarily block the dominant seepage channels of rock samples to prevent cross-flow during the injection of CO2 and nano-agents. It makes full use of the permeation displacement of nano-agents and the diffusion mass transfer of CO2, and realizes the efficient combination of nano-agent displacement and CO2 huff and puff. It can not only effectively utilize the remaining oil around a single well, but also facilitate the establishment of an inter-well displacement system, realize the utilization of the remaining oil between wells, maximize the single-well recovery rate of shale oil, and achieve a better oil enhancement effect. At the same time, based on the experimental results, the relationship curves between different injection pressures, different huff and puff cycles and the crude oil recovery rate of rock samples can more intuitively guide the development of the mine and promote the efficient development of shale oil. Attached Figure Description

[0112] Figure 1 This is a flowchart of the indoor experimental evaluation method for a new shale oil energy replenishment method based on nuclear magnetic resonance in Embodiment 1 of the present invention;

[0113] Figure 2 This is a schematic diagram of the experimental process structure of Embodiment 1 of the present invention;

[0114] Figure 3 This is a flowchart of the indoor experimental evaluation method for a new shale oil energy replenishment method based on nuclear magnetic resonance in Embodiment 2 of the present invention;

[0115] Figure 4 This is a graph showing the relationship between different injection pressures, different throughput cycles, and recovery rate in Example 3 of the present invention.

[0116] Figure 5 This is a graph showing the relationship between different injection pressures, different throughput cycles, and cumulative recovery rate in Embodiment 3 of the present invention. Detailed Implementation

[0117] The technical solutions of the embodiments of the present invention will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only some embodiments of the present invention, and not all embodiments. Based on the embodiments of the present invention, all other embodiments obtained by those skilled in the art without creative effort are within the scope of protection of the present invention.

[0118] Example 1

[0119] Combination Figure 1-2 As shown, this embodiment of the invention provides an indoor experimental evaluation method for a new shale oil refueling method based on nuclear magnetic resonance. The method includes the following steps:

[0120] Step S1. Rock sample pretreatment, specifically including:

[0121] Step S11: Wash the oil, dry, weigh the rock sample, and measure the basic physical properties of the rock sample, including rock sample size, porosity, and permeability;

[0122] Specifically, the rock samples were washed with oil and dried in accordance with the national standard GB / T 29172-2012, and the length L, diameter d, dry weight m1, porosity φ and permeability K of the rock samples were measured.

[0123] Step S12: Perform wire cutting on the rock sample to prepare a rock sample simulating the presence of pressure fractures;

[0124] The wire cutting position is at the center line of the circular end face of the rock sample, and the wire cutting length is half the length of the rock sample.

[0125] Step S2. Saturating the rock sample with heavy water: Place the rock sample into a piston container, evacuate the rock sample and pressurize it with heavy water; wherein, pressurize the rock sample with heavy water until the water saturation of the rock sample is ≥98%;

[0126] Step S2 specifically includes:

[0127] Step S21: Place the rock sample into a piston container with a volume of 1000ml and a pressure resistance of 50MPa, and use a vacuum pump to evacuate the rock sample in the piston container for 4 hours;

[0128] Step S22: Inject heavy water into the piston container until the heavy water fills the entire piston container, and increase the heavy water pressure in the piston container to 20MPa, saturating for 72 hours;

[0129] Step S23: After 72 hours of saturation, measure the weight m2 of the rock sample and calculate the water saturation of the rock sample. If the water saturation of the rock sample is less than 98%, pressurize and saturate it with heavy water again.

[0130] The formula for calculating water saturation is as follows:

[0131]

[0132] In the above formula (1):

[0133] S w —Water saturation of rock sample, %;

[0134] m1—dry weight of rock sample, g;

[0135] m2 — Weight of rock sample after saturation with heavy water, in grams;

[0136] ρ w —Density of heavy water, g / cm³ 3 ;

[0137] V P —Pore volume of rock sample, cm³ 3 ;

[0138] Step S3. Displace the rock sample saturated with heavy water with kerosene until it reaches a state of bound water; specifically including:

[0139] Step S31: Place the rock sample in the core holder and heat it to the formation temperature. Under the conditions of a confining pressure of 5 MPa, an inlet pressure of 2.5 MPa, and an outlet pressure of atmospheric pressure, use kerosene to displace the saturated heavy water until the nuclear magnetic resonance T2 spectrum curve no longer changes with time, and then end the displacement.

[0140] Step S32: Measure the weight of the rock sample after displacement and calculate the original oil saturation and bound water saturation of the rock sample;

[0141] The formula for calculating the original oil saturation is as follows:

[0142]

[0143] In equation (2) above:

[0144] S oi —Original oil saturation of the rock sample, %;

[0145] m2—Weight of the rock sample after saturation with heavy water, in grams;

[0146] m3 — Weight of rock sample after kerosene flooding, in grams;

[0147] ρ w —Density of heavy water, g / cm³ 3 ;

[0148] ρ o1 — Density of kerosene, g / cm³ 3 ;

[0149] V P —Pore volume of rock sample, cm³3 ;

[0150] The formula for calculating the bound water saturation is:

[0151] S wc =1-S oi (3)

[0152] In equation (3) above:

[0153] S wc —Bound water saturation of rock sample, %;

[0154] S oi —Oil saturation of rock sample, %.

[0155] Step S4. Displacing kerosene with formation crude oil: Under simulated formation conditions, kerosene is displaced with formation crude oil to obtain the original oil saturation of the rock sample and its nuclear magnetic resonance T2 spectrum is measured; specifically including:

[0156] Step S41: Place the rock sample in the nuclear magnetic resonance holder, control the confining pressure of the rock sample with a hand pump, then control the pressure at the outlet end of the rock sample with a back pressure pump, and at the same time control the temperature of the rock sample with a heating device to make the pressure and temperature conditions of the rock sample consistent with the original formation conditions.

[0157] Step S42: Under simulated formation conditions, use formation crude oil to displace kerosene and record the oil production V at the rock sample outlet. o Water production V at the rock sample outlet w Simultaneously, the nuclear magnetic resonance T2 spectrum was tested until the nuclear magnetic resonance T2 spectrum curve no longer changed with time, at which point the displacement was terminated.

[0158] Step S43: Calculate the original oil saturation of the rock sample based on the oil production at the outlet end of the rock sample and the water production at the outlet end of the rock sample, and obtain the relationship between the original oil saturation of the rock sample and the nuclear magnetic resonance T2 spectrum based on the calculation results;

[0159] The formula for calculating the original oil saturation of the rock sample is as follows:

[0160]

[0161] In equation (4) above:

[0162] S o —Original oil saturation of the rock sample, %;

[0163] S oi —Oil saturation of rock sample, %;

[0164] V w —Water production at the rock sample outlet, cm 3 ;

[0165] VP —Pore volume of rock sample, cm³ 3 ;

[0166] Step S5. Simulate depletion-type development, measure the nuclear magnetic resonance T2 spectrum, and calculate the oil recovery rate of the rock sample under depletion-type development; specifically including the following steps:

[0167] Step S51: Based on the formation pressure produced on-site, calculate the pressure deficit conditions under laboratory conditions using the similarity principle;

[0168] Step S52: Under simulated laboratory formation conditions, depletion development is carried out to the corresponding pressure conditions to simulate different formation energy depletion states;

[0169] Step S53: During the simulation, monitor the rock sample pressure. When the rock sample pressure drops to the bubble point pressure, stop the depletion development, record the oil production at the outlet, and test the nuclear magnetic resonance T2 spectrum of the rock sample to calculate the oil recovery rate of the rock sample developed by elastic energy during the depletion development process.

[0170] Among them, the oil recovery rate E of rock samples developed using elastic energy during depletion-type development is... d The calculation formula is:

[0171]

[0172] In equation (5) above:

[0173] E d —Simulated depletion-induced oil recovery rate of rock samples, %;

[0174] T 2,max —Maximum relaxation time on nuclear magnetic resonance (NMR), ms;

[0175] T 2,min —Minimum relaxation time of nuclear magnetic resonance, ms;

[0176] M i,d —The nuclear magnetic resonance amplitude value corresponding to the relaxation time when the rock sample pressure equals the bubble point pressure, which is dimensionless;

[0177] M i,i —The nuclear magnetic resonance amplitude value corresponding to the relaxation time in the original state, dimensionless;

[0178] T 2i,d —Relaxation time when rock sample pressure equals bubble point pressure, in milliseconds;

[0179] T 2i,i — Relaxation time in the initial state, in milliseconds;

[0180] Step S6. After depletion-induced development, inject chemical agents to temporarily plug the fracture ends of the rock sample;

[0181] The purpose of injecting chemical agents into the fracture ends of rock samples after depletion development is to temporarily block the dominant seepage fracture channels and prevent the injected CO2 from flowing out and affecting the energy replenishment effect.

[0182] Step S7. Simulate CO2 and nanoparticle injection for enhanced oil recovery under different injection pressures and huff-and-puff cycles, measure nuclear magnetic resonance T2 spectra, and calculate the oil recovery rate of rock samples after enhanced oil recovery under different injection pressures and huff-and-puff cycles; specifically including:

[0183] Step S71: Simulate a single round of refueling development:

[0184] Simulating the minimum miscibility pressure of "CO2-crude oil" and the single-round CO2 injection and nano-agent supplementation development, measuring the nuclear magnetic resonance T2 spectrum, and calculating the minimum miscibility pressure of "CO2-crude oil" and the oil recovery rate of the production rock sample after a single round of supplementation; specifically including:

[0185] Step S711: Based on the experimental rock sample after temporary plugging, CO2 is injected into the simulated depletion development and production end, and nanoparticles are injected into the other end. At the same time, the rock sample pressure is monitored until the rock sample pressure reaches 1.0 MMP (the minimum miscibility pressure of "CO2-crude oil"). The rock sample is then sealed for a period of time (e.g., 8 hours), and the nuclear magnetic resonance T2 spectrum during the sealing process is tested.

[0186] Step S712: After the well is shut down, open the CO2 injection end to simulate production and measure the nuclear magnetic resonance T2 spectrum curve. After the T2 spectrum curve no longer changes, combine it with the nuclear magnetic resonance T2 spectrum curve of the rock sample in its original state to calculate the oil recovery rate of the rock sample under the simulated single round of "chemical plugging + nano-pumping + CO2 huff and puff".

[0187] In step S712, the oil recovery rate E of the produced rock sample after a single round of energy replenishment is... i The calculation formula is:

[0188]

[0189] In the above formula (6):

[0190] E i —Raw oil yield from a single round of refueling of a rock sample, %;

[0191] T 2,max —Maximum relaxation time on nuclear magnetic resonance (NMR), ms;

[0192] T 2,min —Minimum relaxation time of nuclear magnetic resonance, ms;

[0193] m i,d —The NMR amplitude value corresponding to the relaxation time in the original state, dimensionless;

[0194] m i,i —NMR amplitude value corresponding to the relaxation time after energy replenishment, dimensionless;

[0195] T 2i,d — Relaxation time in the initial state, in milliseconds;

[0196] T 2i,i —State relaxation time after energy replenishment development, in milliseconds;

[0197] Step S72: Simulate multiple rounds of energy replenishment development, specifically including:

[0198] Based on the experimental rock sample in step S712, CO2 and nanoparticles were repeatedly injected in multiple rounds at an injection pressure of 1.0 MMP ("CO2-crude oil" minimum miscibility pressure). After the well was shut down for a period of time, the CO2 injection end was opened to simulate production. The nuclear magnetic resonance T2 curve was measured. Combined with the nuclear magnetic resonance T2 spectrum curve of the rock sample in its original state, the oil recovery rate of the simulated CO2 huff and puff + nanoparticle drive multi-round energy replenishment production was achieved.

[0199] In step S72, the oil recovery rate E of the produced rock sample after multiple rounds of energy replenishment is... i The formula for calculating ' is:

[0200]

[0201] In equation (7) above:

[0202] E i' —Oil recovery rate of produced rock samples after multiple rounds of refueling, %;

[0203] T 2,max —Maximum relaxation time on nuclear magnetic resonance (NMR), ms;

[0204] T 2,min —Minimum relaxation time of nuclear magnetic resonance, ms;

[0205] m i,d —The NMR amplitude value corresponding to the relaxation time in the original state, dimensionless;

[0206] m i,i —NMR amplitude value corresponding to the relaxation time after energy replenishment, dimensionless;

[0207] T 2i,d — Relaxation time in the initial state, in milliseconds;

[0208] T 2i,i —State relaxation time after energy replenishment development, in milliseconds;

[0209] Since the oil recovery rate of the production rock sample after each round of energy replenishment is calculated by the surface area of ​​the nuclear magnetic resonance, the calculation process of formula (7) and formula (6) is the same.

[0210] Step S73: Select parallel rock samples and repeat the rock sample experiment according to steps S1-S6. Based on the parallel experimental rock samples (i.e. different rock samples), repeat the experiment in steps S71-S72 under the condition of changing the CO2 injection pressure P1 to obtain the oil recovery rate of the rock samples produced after replenishment under different injection pressures and huff and puff cycles. Stop the experiment when the oil recovery rate no longer changes and calculate the total recovery rate of the rock samples.

[0211] The CO2 injection pressure P1 is set to 0.5-2 MMP, where MMP is the minimum miscibility pressure between CO2 and crude oil.

[0212] Example 3

[0213] like Figure 3 As shown, based on steps S1-S7 in Embodiment 2, this embodiment of the invention further includes the following steps:

[0214] Step S8. Based on the experimental results, plot the relationship curves between different injection pressures, different throughput cycles and the oil recovery rate of the rock sample to obtain more intuitive experimental evaluation results.

[0215] Example 3

[0216] The embodiments of this invention are specific application examples to further illustrate the specific implementation process of the indoor evaluation experimental method for a new shale oil regeneration method based on nuclear magnetic resonance in Examples 1-2, which specifically includes the following steps:

[0217] Step S1: Pre-treat the rock sample, including washing off the oil, drying, and measuring the basic physical properties of the rock sample: length L = 10 cm, diameter d = 2.5 cm, dry weight m1 = 122.71 g, porosity φ = 10.05%, permeability K = 0.06 mD; and cut and create fractures in the rock sample.

[0218] Step S2: Saturate the experimental rock sample with heavy water and calculate the water saturation S. w =99.3%;

[0219] Step S3: Displace the rock sample saturated with heavy water with kerosene until it reaches the bound water state, and calculate the original oil saturation S. oi =54.2%, calculate the bound water saturation S wc =45.8%;

[0220] Step S4: Displace kerosene with formation crude oil and calculate the original oil saturation S of the rock sample. o =53.9%;

[0221] Step S5: Simulate depletion-type development. Calculate the oil recovery rate E of the depletion-type development rock sample based on the nuclear magnetic resonance T2 spectrum. d=9.36%;

[0222] Step S6: After depletion-induced development, inject chemical agents to temporarily plug the fracture ends of the rock sample;

[0223] Step S7: Simulate CO2 and nanoparticle injection for enhanced oil recovery under different injection pressures and different huff-and-puff cycles, measure nuclear magnetic resonance T2 spectra, and calculate the oil recovery rate of rock samples after enhanced oil recovery under different injection pressures and huff-and-puff cycles; specifically including:

[0224] Step S71: Simulate a single-round replenishment development and calculate the oil recovery rate E of the production rock sample after a single round of replenishment based on the nuclear magnetic resonance T2 spectrum. i ;

[0225] Step S72: Simulate multiple rounds of energy replenishment development. Based on the nuclear magnetic resonance T2 spectrum, calculate the oil recovery rate E of the rock sample under different throughput rounds. i and cumulative yield;

[0226] Step S73: Select parallel rock samples and repeat the rock sample experiments according to steps S1-S6. Then, based on the repeated rock sample experiments, change the CO2 injection pressure to 1 MPa, 1.2 MPa, and 1.5 MPa, and repeat steps S71-S72 to obtain the oil recovery rate of the rock sample after replenishment under different injection pressures and different huff and puff cycles. Stop the experiment when the oil recovery rate no longer changes. Based on the nuclear magnetic resonance T2 spectrum, calculate the periodic recovery rate and cumulative recovery rate of the rock sample under different huff and puff cycles at injection pressures of 1.2 MPa ("CO2-oil" minimum miscibility pressure") and 1.5 MPa ("CO2-oil" minimum miscibility pressure). The calculation results are shown in Tables 1 and 2 below.

[0227] Table 1. Recovery rate under different injection pressures and different throughput cycles.

[0228]

[0229] Table 2 Cumulative recovery rate under different injection pressures and different throughput cycles.

[0230]

[0231] Step S8. Based on the experimental results, plot the relationship curves between different injection pressures, different huff and puff cycles, and the oil recovery rate of the rock sample, as shown below. Figure 4 , Figure 5 As shown, this allows for a more intuitive evaluation of experimental results.

[0232] in, Figure 4 The graph shows the relationship between different injection pressures, different throughput cycles, and the recovery rate over time. Figure 5 A graph showing the relationship between different injection pressures, different throughput cycles, and cumulative recovery rate.

[0233] Based on the above experimental process, it can be seen that the recovery rate of crude oil in depleted development is only 9.36% (see experimental step S5). Under injection pressures of 1.0 MMP (minimum miscibility pressure of "CO2-crude oil"), 1.2 MMP, and 1.5 MMP, the recovery rate of crude oil in a single round of huff and puff after replenishment is higher than that in depleted development (see Table 1). After multiple rounds of huff and puff, the cumulative recovery rate of crude oil in the rock sample is much higher than that in depleted development (see Table 2). The replenishment development method of "chemical plugging + nano-pumping + CO2 huff and puff" has achieved good development results.

[0234] At the same time, combined Figure 4 , Figure 5 It can be seen that under an injection pressure of 1.5 MMP ("CO2-crude oil" minimum miscibility pressure) the energy replenishment development method of "chemical plugging + nano-pumping + CO2 huff and puff" has a significant effect on improving the recovery rate. After the fourth round of huff and puff, the cumulative recovery rate of the rock sample crude oil reached its peak, and the effect of subsequent rounds of huff and puff on improving the recovery rate was not obvious.

[0235] Based on the above analysis, the mine can achieve good development results by adopting a four-round throughput replenishment development method with an injection pressure of 1.5 MMP ("CO2-crude oil" minimum miscibility pressure).

[0236] The above description is merely an embodiment of the present invention and is not intended to limit the present invention. Any modifications, equivalent substitutions, and improvements made within the scope of the present invention should be included within the protection scope of the present invention.

Claims

1. A method for evaluating a new way of shale oil energy supplement based on nuclear magnetic resonance, characterized in that, The method comprises the following steps: Step S1. Pretreatment of rock sample; Step S2. Put the rock sample into the piston container, vacuumize the rock sample and pressurize to saturate heavy water; Step S3. Displace the heavy water-saturated rock sample with kerosene until the bound water state; Step S4. Displace the kerosene with formation crude oil under simulated formation conditions to obtain the original oil saturation of the rock sample and measure the nuclear magnetic resonance T2 spectrum thereof; Step S5. Simulate the depletion development, measure the nuclear magnetic resonance T2 spectrum, and calculate the original oil recovery of the rock sample in the depletion development; Step S6. After the depletion development, inject the chemical agent into the fracture end of the rock sample to implement the temporary plugging; Step S7. Simulate the injection of CO2 and nano-agent energy supplement development under different injection pressures and different huff and puff cycles, measure the nuclear magnetic resonance T2 spectrum, and calculate the original oil recovery of the rock sample after the energy supplement under different injection pressures and huff and puff cycles.

2. The method according to claim 1, wherein, The step S1 specifically comprises: Step S11: Wash oil, dry, weigh the rock sample, and measure the basic physical properties of the rock sample; The basic physical properties of the rock sample comprise the size of the rock sample, the porosity φ and the permeability K, wherein the size of the rock sample comprises the length L and the diameter d of the rock sample; Step S12: Linear cut the rock sample to prepare the rock sample with simulated fracture.

3. The method according to claim 2, wherein the method is characterized by, In the step S12, the linear cutting position is the circular center line of the end face of the rock sample, and the linear cutting length is half of the length of the rock sample.

4. The method according to claim 1, wherein, In the step S2, the heavy water is pressurized to saturate the rock sample to a water saturation of ≥98%.

5. The method according to claim 4, wherein the method is characterized by, The step S2 specifically comprises: Step S21: Place the rock sample in a piston container with a volume of 1000ml and a pressure resistance of 50MPa, and use a vacuum pump to vacuumize the rock sample in the piston container for 4-6h; Step S22: Inject heavy water into the intermediate container until the heavy water fills the entire piston container, and pressurize the heavy water in the piston container to 20MPa, and saturate for 72h; Step S23: Measure the weight m2 of the rock sample after saturating for 72h, calculate the water saturation of the rock sample, and if the water saturation of the rock sample is less than 98%, re-pressurize to saturate the heavy water; The calculation formula of the water saturation is as follows: In the formula, m1 is the dry weight of the rock sample, g; m2 is the weight of the rock sample after saturating with heavy water, g. S w — Core water saturation, %; The step S3 specifically comprises: Step S31: Place the rock sample in a core holder and heat it to the formation temperature, and displace the heavy water with kerosene under the conditions of a confining pressure of 5MPa, an inlet end pressure of 2.5MPa and an outlet end atmospheric pressure, until the nuclear magnetic resonance T2 spectrum curve does not change with time, and then end the displacement; p w - density of heavy water, g / cm 3 ; V P — rock sample pore volume, cm3 3 .

6. The method according to claim 1, wherein, Step S32: Measure the weight of the rock sample after displacement, and calculate the original oil saturation and the irreducible water saturation of the rock sample. In the step S32, the calculation formula of the original oil saturation is as follows: In the formula, m2 is the weight of the rock sample after saturating with heavy water, g; m3 is the weight of the rock sample after the kerosene displacement, g.

7. The method according to claim 6, wherein the method is characterized by, The calculation formula of the irreducible water saturation is as follows: In the formula, The step S4 specifically comprises: S oi — rock sample initial oil saturation, %; Step S41: Place the rock sample in a nuclear magnetic resonance holder, control the confining pressure of the rock sample by using a hand pump, then control the outlet end pressure of the rock sample by using a back pressure pump, and control the temperature of the rock sample by using a heating device, so that the pressure and temperature conditions of the rock sample are consistent with the original formation conditions; ​ p w - density of heavy water, g / cm 3 ; p o1 - kerosene density, g / cm 3 ; V P — rock sample pore volume, cm 3 ; ​ S wc = 1 - S oi ​ S wc — rock sample irreducible water saturation, %; S oi — Oil saturation of rock sample, %.

8. The method according to claim 1, wherein the method is characterized by, ​ ​ Step S42: displace kerosene with formation crude oil under simulated formation conditions, record oil production V at the outlet end of the rock sample o , water production V at the outlet end of the rock sample w , and simultaneously test the nuclear magnetic resonance T2 spectrum, and after the nuclear magnetic resonance T2 spectrum curve does not change with time, end the displacement; Step S43: calculating the original oil saturation of the rock sample according to the oil production at the outlet end of the core rock sample and the water production at the outlet end of the core rock sample, and obtaining the relationship between the original oil saturation of the core rock sample and the nuclear magnetic resonance T2 spectrum according to the calculation result.

9. The method according to claim 8, wherein the method is characterized by, In the step S43, the calculation formula of the original oil saturation of the core rock sample is as follows: In the formula, SOR is the original oil saturation of the core rock sample, SOR0 is the original oil saturation of the core rock sample, SORf is the oil saturation of the core rock sample at the outlet end of the core rock sample, and SORf0 is the oil saturation of the core rock sample at the outlet end of the core rock sample. S o — rock sample initial oil saturation, %; S oi — rock sample oil saturation, %; V w — Water production at the outlet end of the rock sample, cm 3 ; V P — rock sample pore volume, cm3 3 .

10. The method of claim 1, wherein the method is characterized by: The step S5 specifically includes the following steps. Step S51: calculating the pressure depletion condition under the laboratory condition by using the similarity principle according to the formation pressure of the field production; Step S52: simulating the different formation energy depletion states by depleting the simulation laboratory formation condition to the corresponding pressure condition; Step S53: monitoring the pressure of the core rock sample in the simulation process, stopping the depletion development when the pressure of the core rock sample drops to the bubble point pressure, recording the oil production at the outlet end, testing the nuclear magnetic resonance T2 spectrum of the core rock sample, and calculating the oil recovery rate of the core rock sample relying on the elastic energy development in the depletion development process.

11. The method according to claim 10, wherein the method is characterized by, In the step S53, the oil recovery ratio E of the rock sample depending on the elastic energy in the depletion development process d The calculation formula is as follows: In the formula, SOR is the original oil saturation of the core rock sample, SOR0 is the original oil saturation of the core rock sample, SORf is the oil saturation of the core rock sample at the outlet end of the core rock sample, and SORf0 is the oil saturation of the core rock sample at the outlet end of the core rock sample. E d - simulated oil recovery from a depleted rock sample, %; T 2,max — maximum relaxation time in nuclear magnetic resonance, ms; T 2,min — nuclear magnetic resonance minimum relaxation time, ms; M i,d — the relaxation time corresponding to the nuclear magnetic resonance amplitude value, dimensionless, when the rock sample pressure is equal to the bubble point pressure. M i,i — the nuclear magnetic resonance amplitude value corresponding to the original state relaxation time, dimensionless; T 2i,d — relaxation time of the rock sample at the pressure equal to the bubble point pressure, ms; T 2i,i — original state relaxation time, ms.

12. The method of claim 1, wherein the method is characterized by: The step S7 specifically includes the following steps. Step S71: simulating the single round of energy supplement development: Simulating the "CO2-oil” minimum miscibility pressure and the single round of CO2 injection and nano-agent energy supplement development, measuring the nuclear magnetic resonance T2 spectrum, and calculating the "CO2-oil” minimum miscibility pressure and the oil recovery rate of the production core rock sample after the single round of energy supplement; specifically including the following steps. Step S711: based on the experimental core rock sample after the temporary plugging, injecting CO2 at the production end of the simulation depletion development and injecting nano-agent at the other end, monitoring the pressure of the core rock sample at the same time, until the pressure of the core rock sample reaches the "CO2-oil” minimum miscibility pressure, then closing the well for a period of time, and testing the nuclear magnetic resonance T2 spectrum in the well closing process at the same time; Step S712: after the well closing is completed, opening the CO2 injection end to simulate the production, measuring the nuclear magnetic resonance T2 spectrum curve, until the nuclear magnetic resonance T2 spectrum curve no longer changes, combining the nuclear magnetic resonance T2 spectrum curve of the original state of the core rock sample, and calculating the oil recovery rate of the core rock sample in the simulation single round of "chemical agent plugging + nano-agent flooding + CO2 huff and puff” energy supplement production; Step S72: simulating the multi-round energy supplement development, specifically including the following steps. Based on the experimental core rock sample in the step S712, repeatedly injecting CO2 and nano-agent for multiple rounds under the "CO2-oil” minimum miscibility pressure, opening the CO2 injection end to simulate the production after closing the well for a period of time, measuring the nuclear magnetic resonance T2 curve, combining the nuclear magnetic resonance T2 spectrum curve of the original state of the core rock sample, and calculating the oil recovery rate of the core rock sample in the simulation CO2 huff and puff + nano-agent flooding multi-round energy supplement production; Step S73: selecting parallel core rock samples, repeating the core rock sample experiments according to the steps S1-S6, based on the parallel experimental core rock samples, repeating the steps S71-S72 experiments under the condition of changing the CO2 injection pressure P1, obtaining the oil recovery rate of the core rock sample produced after the energy supplement under different injection pressures and huff and puff rounds, stopping the experiment until the oil recovery rate no longer changes, and calculating the total recovery rate of the core rock sample.

13. The method of claim 12, wherein the method is characterized by: The step S712, a single round of energy after the production of rock sample oil recovery E i The formula is: In the formula, SOR is the original oil saturation of the core rock sample, SOR0 is the original oil saturation of the core rock sample, SORf is the oil saturation of the core rock sample at the outlet end of the core rock sample, and SORf0 is the oil saturation of the core rock sample at the outlet end of the core rock sample. E i — Rock sample single round of energy supplement after production rock sample oil yield, %; T 2,max — maximum relaxation time in nuclear magnetic resonance, ms; T 2,min — nuclear magnetic resonance minimum relaxation time, ms; m i,d - the nuclear magnetic resonance amplitude value, dimensionless, corresponding to the relaxation time in the original state; m i,i - the energy supply develops a nuclear magnetic resonance amplitude value corresponding to the relaxation time, dimensionless; T 2i,d — original state relaxation time, ms; T 2i,i — Energy supplement development after state relaxation time, ms.

14. The method of claim 12, wherein the method is characterized by: The step S72, after multiple rounds of energy supplement, the production of rock sample oil recovery E i The formula for calculating the formula is: In the formula, SOR is the original oil saturation of the core rock sample, SOR0 is the original oil saturation of the core rock sample, SORf is the oil saturation of the core rock sample at the outlet end of the core rock sample, and SORf0 is the oil saturation of the core rock sample at the outlet end of the core rock sample. E i % recovery of oil from produced rock samples after multiple rounds of energy supplementation; T 2,max - maximum relaxation time in nuclear magnetic resonance, ms; T 2,min — minimum nuclear magnetic resonance relaxation time, ms; m i,d - the nuclear magnetic resonance amplitude value, dimensionless, corresponding to the relaxation time in the original state; m i,i - the energy supply develops a nuclear magnetic resonance amplitude value corresponding to the relaxation time, dimensionless; T 2i,d — original state relaxation time, ms; T 2i,i — Energy supplement development after state relaxation time, ms.

15. The method of claim 12, wherein the method is characterized by: In the step S7, the value of the CO2 injection pressure P1 is 0.5-2MMP, and MMP is the "CO2-oil” minimum miscibility pressure.

16. The method of any one of claims 1-15, wherein the method is a laboratory evaluation method for a new way of shale oil energy supplement based on nuclear magnetic resonance. The step S7 further includes the following steps. Step S8. Based on the experimental results, a curve of different injection pressures, different throughput rounds and the oil recovery rate of the rock sample is drawn.

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