Characterization of asphaltene deposition and formation damage during CO₂ miscible/immiscible flooding in Low-permeability sandstones using NMR T₁-T₂

Abstract

CO₂ flooding in low-permeability oilfields has been widely adopted worldwide as it significantly enhances oil recovery. However, when CO₂ is injected into the reservoir, asphaltene precipitation may occur, damaging the reservoir and resulting in a less pronounced improvement in recovery rate. There is few researchers have directly studied asphaltene deposition during CO₂ displacement at the moment. To shed light on the asphaltene deposition characteristics in CO2 static injection into oil and during CO₂ miscible/immiscible flooding, analyse the degree of damage caused by asphaltene deposition on the porosity and permeability of the core, a few samples were selected from the Tarim Oilfield for four-component experiments and CO₂ core flooding experiments. Through four-component testing experiments, the proportion of asphaltene deposition in oil at different CO₂ injection concentration was determined. When the molar ratio of injected CO₂ to crude oil reached 9:5, an inflection point in the ​relative asphaltene deposition amount was observed. Beyond this threshold, continued CO₂ injection resulted in no significant increase in the relative deposition amount. At a molar injection ratio of 3:1, the ​asphaltene deposition mass fraction peaked at 7.76% with a ​deposition efficiency of 86.7%. At the same time, we conducted CO₂ miscible flooding/immiscible flooding experiment to characterize of asphaltene deposition and reservoir damage degree using NMR technology. The ​asphaltene-associated signatures in NMR T1-T2 relaxation spectra are defined within the ​shared parameter space where: 5 < T₁/T₂ < 14 and T₂ within 1–5 ms. Based on NMR T₁-T₂ of CO₂ flooding, the amount of asphaltene precipitation in the core sample can be visually observed. The asphaltene deposition percentages caused by CO₂ immiscible flooding, near-miscible flooding, and miscible flooding are 11.97%, 16.34%, and 50.64%, respectively. By comparing the T2 spectrum during re-saturation with that of the initial condition, it is evident that asphaltene is mostly deposited in the mesopores and macropores. The pore obstruction caused by asphaltene deposition prevents the resaturated crude oil from entering the pores, which lowers the T2 spectrum curves by 1–10 and > 10 ms. The corresponding percentages of reduction in porosity are 6.71%, 11.8%, and 17.36%, while the percentages of permeability impairment are 23.29%, 60.88%, and 65.25%, respectively. Determining the percentage of asphaltene deposits during CO₂ injection and understanding the extent of damage to the reservoir can significantly improve the effectiveness of CO₂ in EOR.

Supplementary Information

The online version contains supplementary material available at 10.1038/s41598-025-00006-5.

Introduction

The need for oil in China has increased as the global economy continues to grow. Since 2008, China’s domestic oil production has remained stable; however, oil imports have progressively increased, with up to 70% of its supply being imported. The proportion of low- and ultralow-permeability oil resources in freshly discovered oilfields in China has steadily increased in recent years, accounting for two-thirds of all domestic oil resources^1,2. Furthermore, they contain the largest reserves in any domestic oil resource category, indicating huge development potential. Low-permeability reservoirs have substantial deposits; however, their development is difficult. When extracted using natural energy, the production capacity of poorly permeable oil fields rapidly declines owing to low formation pressure and energy. Therefore, developing oil resources for primary recovery is challenging. Besides distinct variations in reservoir characteristics, poor continuity, and high heterogeneity, low-permeability oil fields exhibit high connectedness and flow resistance. Consequently, secondary oil recovery cannot considerably increase the recovery rate of low-permeability reservoirs, and water injection wells have a poor injection capacity. The issues in the development of low-permeability oil fields have been addressed largely by the development of CO₂ flooding technology^3–6, CO₂ is widely used in drilling and fracturing because of its unique phase characteristics (liquid/supercritical). In drilling, liquid CO₂ can replace water-based drilling fluids, prevent clay expansion, and reduce the risk of wellbore instability through low temperature plasticizing (-40 to 0 °C). In fracturing, supercritical CO₂ (ScCO₂, > 7.38 MPa, 31.1 °C) has low viscosity, high dispersion and strong rock cracking ability, can form complex fracture network, and no water phase damage, especially suitable for low permeability reservoirs^7,8.

Since CO₂ dissolves in oil more easily than in water, CO₂ flooding technology effectively aids in extracting light (C₁–C₇) and intermediate components (C₇–C₂₀) from oil. This promotes the miscibility of CO₂ with oil, reducing the interfacial tension between the fluids and oil and the viscosity of the oil⁹. Consequently, reservoir oil recovery has improved^10,11. A notable successful case of CO₂-enhanced oil recovery was the SACROC block project in the Kelly Snyder Oilfield, which tripled its well production¹². Furthermore, in 1963, a CO₂ EOR technology experiment conducted in the Daqing Oilfield significantly improved the recovery of low-permeability reservoirs in China¹³. However, despite the advances in current CO₂ flooding technology, the nonpolar nature of CO₂ can lead to considerable asphaltene deposition within the reservoir during injection for oil recovery enhancers. The dissolution of CO₂ in the oil disrupts the equilibrium system, resulting in asphaltene deposition. These deposits obstruct small pores and throats, altering pore structure¹⁴, reducing porosity¹⁵, decreasing permeability^16–18, and ultimately causing a sharp decline in oil production^19,20.

In 1837, Boussingault introduced the concept of asphaltenes for the first time. Asphaltene, a crucial component of oil, is commonly considered a hydrocarbon-derived compound composed of nitrogen, oxygen, sulfur, and other heavy hydrocarbons^21,22. The presence of asphaltenes in oil can lead to deposition under specific temperature, pressure, and foreign fluid conditions, which can adversely affect oil recovery. Since the 1980s, numerous laboratory experiments have been conducted to explore the structure, deposition characteristics, migration, and pore and throat plugging of asphaltenes. These findings have been applied in oil fields to assist in identifying the initial deposition point of asphaltenes and assessing the damage caused by them to the reservoir^23–26. Notably, China has begun to recognize the detrimental effects of asphaltene deposition on reservoirs. Early laboratory research relied on asphaltene precipitation, light scattering, and titration methods²⁷ to investigate the impact of asphaltene destruction on oil recovery. Currently, both domestic and international scholars commonly employ flooding experiments to determine the extent of permeability reduction and damage caused by asphaltene deposition in reservoirs²⁸. However, microscopic pore-scale analyses of the impact of asphaltene deposition on reservoirs remain scarce.

In recent years, nuclear magnetic resonance (NMR) T₁-T₂ technology has demonstrated significant advantages in categorizing fluid types and quantitatively describing fluid features in porous media. Therefore, in this study, the low-permeability reservoir oil in the Tarim Oilfield was selected as the sample site. Both NMR and four-component testing technologies were employed to conduct asphaltene deposition experiments in the bulk phase with varying mole numbers of CO₂ injection. Additionally, asphaltene deposition damage experiments were performed on the core samples using CO₂ flooding at three different injection pressures. The effects of the CO₂ injection amount and injection pressure on the asphaltene deposition characteristics and their subsequent damage to reservoir rock permeability were analyzed. These findings could provide a solid foundation for the successful implementation of CO₂ flooding as an effective method for enhancing oil recovery in low-permeability reservoirs, such as in the Tarim Oilfield.

Samples characterization

The experimental oil is oil from Well DH6, the density and viscosity of which were 0.87 g/cm³ and 21.32 mPa·s at room temperature, and the contents were mainly C₅–C₁₅ (as shown in Fig. 1),. The content of C₈ reached 12.86, and C₉ was second only to C₈, its content was 10.62. DH6 oil is dominated by light and medium hydrocarbons and has high viscosity.

Fig. 1.

Composition analysis result of the oil used in this study.

The process of CO₂ flooding has a significant impact on asphaltene deposition and the characteristics of deposition damage, regardless of whether CO₂ is miscible with oil. To get the miscibility pressure of CO₂ with experimental oil, this study first tested the characteristics of interfacial tension between oil and CO₂ with a high-temperature and high-pressure interfacial tension meter (the maximum working pressure was 70 MPa and temperature was 200 °C, Fig. 2) as a function of pressure and then determined the minimum miscibility pressure of oil and CO₂.

Fig. 2.

High-temperature and high-pressure interfacial tension meter.

The main experimental steps followed were as follows:

1) The suspension chamber was cleaned with petroleum ether (PE) and toluene (C₇H₈), purged with hot nitrogen, the petroleum ether or toluene on the wall of the suspension chamber was removed, and then the suspension chamber was pumped to a vacuum.

2) The system was heated to 143.5 °C (formation temperature) and kept constant, and then slowly CO₂ was injected into the suspended droplet chamber while the system was pressed to reach the experimental set pressure value.

3) When the temperature and pressure of the system became stable, the oil sample of the formation entered the drop chamber through the capillary probe. When oil drops of stable size and status appeared at the top of the capillary probe, the camera of the system captured pictures of them (Fig. 3). According to the shape of the oil drops, the Andreas surface selection method (1938) was used to calculate the interfacial tension between CO₂ and oil²⁹.

Fig. 3.

Oil-CO₂ interfacial tension drawing (from left to right: 0.1, 3, 9, 15, and 17 MPa).

4) Repeat steps 1 and 3, keep the temperature unchanged, and gradually increase the test pressure from 0.3 MPa until the oil-gas interface disappears. The experimental data graph of the oil-CO₂ interfacial tension (Fig. 4) showed that the interfacial tension of the oil and gas phases decreases with an increase in the system pressure and that the interfacial tension is linearly related to the reciprocal of the pressure. Therefore, the primary contact miscible pressure of CO₂–oil can be predicted to be approximately 23.3 MPa.

Fig. 4.

Oil trend of interfacial tension and pressure-1 of CO₂/oil.

The low-permeability sandstone from well DH6 of Tarim Oilfield was selected as the core in this experiment, and the physical properties of the core are shown in Table 1. After washing oil and salt, the core was dried and weighed until the weight remained unchanged, and permeability and porosity were tested. Permeability was measured by gas and porosity was measured by saturation weighing method.

Table 1.

Cores used for the CO₂ flooding experiment.

Sample number	diameter /mm	length /mm	porosity /%	permeability /mD	Injection pressure /MPa
3–10	25.08	81.37	11.498	0.758	15
6–10	25.05	80.41	12.396	0.504	5
6–31	25.24	80.45	10.226	0.374	25

The core casting thin section results (shown in Fig. 5) suggest that the core pore structure is dominated by intergranular dissolved pores and primary intergranular pores, with a small number of intragranular dissolved pores.

Fig. 5.

Dissolution pores (blue circles) and intergranular pores (red circles) observed in cast slices from well DH6.

Experiments

Asphaltene deposition in oil

The asphaltene deposition experiment in oil is as shown in Scheme 1, which mainly includes a PVT instrument (temperature resistance of 200 °C and pressure resistance of 150 MPa), a data acquisition system, a CO₂ gas source, and a temperature control system. The experimental steps were as follows:

1. A certain volume of oil was transferred into the PVT reactor and heated up to a temperature of 143.5 °C to calculate the mole number of oil and determine the molar ratio of CO₂ to oil (3:5, 9:5, 12:5, 3:1, 6:1, and 12:1).

2. CO₂ was pressed into an intermediate container at a molar ratio of 3:5, and then heated and pressed up to the required conditions (143.5 °C and 56.47 MPa, respectively).

3. The CO₂ in the intermediate container was injected into the PVT reactor, stirred for 24 h, and maintained for 24 h to fully deposit asphaltene. Oil was removed from the middle and upper layers of the PVT reactor to extract the four components according to the NB/SH/T 0509–2010 petroleum asphalt four component determination method (the device is shown in Fig. 6), and the asphaltene content was measured using the difference method.

4. The mole amount of CO₂ injection was changed, and steps 2 and 3 were repeated to determine the relative deposition amount of asphaltene under different injection amounts.

Scheme 1.

Static experiment of asphaltene deposition.

Fig. 6.

Oil four component separation plant.

Asphaltene deposition by CO₂ core flooding

NMR theory

NMR is a technique that can easily detect the relaxation signals of hydrogen-containing fluids in porous media and analyze their contents. The relaxation mechanism consists of longitudinal relaxation time T₁ and transverse relaxation time T₂^30–32, both of which are composed of surface relaxation T_S, bulk relaxation T_B, and diffusion relaxation T_D, as expressed below:

1

2

where T₂ is the transverse relaxation time (ms); (1/T₁)_S and (1/T₂)_S are the relaxation contributions of the rock particle surface (ms^− 1); (1/T₁)_B and (1/T₂)_B are the relaxation contributions of the fluid itself (ms^− 1); and (1/T₂)_D is the relaxation contribution of the molecular diffusion (ms^− 1).

Since different fluids have different T₁/T₂ ratios in NMR spectroscopy, asphalt, oil, and water can be identified. Previous researchers found that the water phase in the T₁-T₂ spectrum was closer to the T₁/T₂ = 1 boundary, while the oil phase was closer to the lower left short relaxation time than the water phase. Furthermore, when the ratio of longitudinal and transverse relaxation times is higher than T₁/T₂ > 5, with a shorter relaxation time, the phase is asphaltene^33,34.

When the magnetic field is uniform and the echo interval is sufficient, the influence of diffusion relaxation can be ignored. The bulk relaxation T_2B of the fluid is generally between 2 and 3 s, which can be ignored compared to the transverse relaxation time T₂. Then, Eq. (2) can be simplified as folows:

3

where ρ₂ is surface relaxation rate (µm/ms); S is the total pore surface area (µm²); V is pore volume (µm³); Fr is pore shape factor; and r is the pore radius (mm). When the formation pores are approximately cylindrical and spherical, Fr = 2 and Fr = 3, respectively.

The transverse relaxation time T₂ of NMR is related to the pore size and shape. When the pore-throat shape factor is constant, the smaller the transverse relaxation time, the smaller the corresponding pore throat. When a fluid phase saturates a porous medium, the NMR T₂ spectrum can also be used to calculate the permeability of rock^22–35. The calculation formula can be expressed as follows:

4

5

where K_wi is phase permeability of the core wetting phase (mD); C is the coefficient of rock mineral composition that can be fitted by experimental data, dimensionless; m and n are coefficients related to the physical properties and microstructure coefficients of the cores, equal to 4 and 2, respectively, dimensionless; and T_2m(i) is the logarithmic mean value of the transverse relaxation time (ms).

As shown in Scheme 2, the flowchart of the CO₂ flooding experiment includes the injection system, backpressure system, core gripper, and NMR system.

Scheme 2.

CO₂ flooding flow chart.

The experimental steps were as follows:

1. The core was vacuumed This is becauseand saturated with formation oil at a formation temperature (143.5 °C) for 48 h. Then, the NMR T₁-T₂ atlas of the core was measured, and core saturation was calculated.

2. The core was loaded into the core holder, CO₂ was pre-heated to the formation temperature, and then pressed to a pressure slightly lower than that required for the experiment. The confining pressure was set to 30 MPa, and the outlet pressure controlled by the backpressure valve reached a pore pressure of 5 MPa. While slowly injecting the high-pressed CO₂ gas into the core at a rate of 0.1 mL/min, the pressure difference between the two ends of the experimental core, and oil and gas production. Recording was stopped when the core stopped producing oil for a period of time. Finally, the weight of the core was measured, and NMR T₁-T₂ map was prepared after core flooding.

3. The core was washed to re-saturate the oil under the same experimental conditions, obtain the nuclear magnetic resonance T₁-T₂ map of the core after saturation, and calculate the asphaltene deposition, porosity, permeability, and asphaltene damage rate of the core after quadratic saturation of the oil.

4. Steps 2 and 3 were repeated under pressure of 15 MPa and 25 MPa, respectively, to obtain asphaltene deposition damage data for immiscible, near-miscible, and mixed phases.

Results and discussion

Asphaltene deposition in oil

Figures 7 and 8 show the variation in features of asphaltene dissolution and deposition under different CO₂ injection amounts. These findings indicated that asphaltene is sensitive to CO₂ density. When the molar volume ratio of CO₂-to-oil increased from 3:5 to 9:5, the percentage of asphaltene deposited in the oil increased rapidly from 3.21 to 7.45%. With an increase in CO₂ injection, the asphaltene deposited in the oil showed a slow increase and remained stable after reaching its peak. At this point, CO₂ and oil may coexist in the bulk phase. When the molar ratio of the injected CO₂-to-oil reached 3:1, the asphaltene deposition amount reached a maximum of 7.76%, and the deposition rate reached 86.7%. With the increase of CO₂ ratio, asphaltene deposition initially increased and then stabilized. In the low molar ratio (3:1→9:5) stage, the deposition volume increased rapidly from about 4–7.76% (peak). When the molar ratio exceeds 9:5, the deposition amount tends to be stable (at 6:1→12:1, it stays in the range of 7.5%~8%). The proportion of dissolved asphaltene changes inversely with the amount deposited, from about 8–4.5% in the initial stage (3:1→9:5), and then slowly decreases to less than 3% as the CO₂ proportion increases. A continuous increase in the injected CO₂ no longer led to an increase in the relative amount of asphaltene deposition. The curve gradually flattened, indicating that the asphaltene content in the oil tends to stabilize and the CO₂ dissolved in the oil reaches equilibrium. When the molar ratio of the injected CO₂-to-oil was 6:1, the relative asphaltene deposition amount decreased slightly, indicating that a small part of the asphaltene deposited was redissolved in the oil. This is because the dissolution of CO₂ in the oil leads to the extraction of light components, which change the composition of the oil and destroy the balance of the aromatic hydrocarbon resin asphaltene colloidal solution system in the oil, causing the asphaltene to condense and precipitate. Furthermore, with an increase in CO₂, which is a nonpolar substance, CO₂ molecules diffuse into the oil more rapidly, disturbing the distribution of asphaltene in the oil and further increasing its deposition. After CO₂ injection, CO₂ molecules enter the pores and occupy the surface space of asphaltene, resulting in a decrease in the colloid concentration at the asphaltene surface. Eventually, the hydrogen bonds in the asphaltene molecules gather, resulting in associated sedimentation.

Fig. 7.

Static deposition of asphaltene.

Fig. 8.

Relative static deposition of asphaltene.

Asphaltene deposition during CO₂ core flooding

Initially, from the T₁-T₂ results, we obtained the fluid distribution throughout the core. The positions of asphaltenes in the images were determined jointly based on the distribution ranges of T₂ and T₁/T₂. By comparing the changes in the size of the T₁-T₂ image regions before and after the experiment, we analyzed the variation in asphaltene precipitation quantity with displacement pressure. Furthermore, we calculated and analyzed the relative deposition amount of asphaltenes based on the size of the asphaltene precipitation regions in the T₁-T₂ images. Additionally, we analyzed the changes in core physical properties by comparing the T₂ spectra of the initial oil-saturated state and the re-saturated oil state before and after the experiment. This analysis assessed the degree of reduction in the core porosity and permeability caused by asphaltene precipitation.

Figure 9A shows the test results of the NMR T₁-T₂ map of the oil. The map demonstrates multiple independent distributions. Figure 9B shows the test results of the NMR T₁-T₂ map of deposited asphaltene. By contrasting Fig. 9A and B, the asphaltene that has been deposited in the sediment and the asphaltene that has been present in oil display similar response signals in the NMR spectrum. Asphaltene signal located at 5 < T₁/T₂ < 14 and T₂ within 1–5 ms. The proportion of 5 < T₁/T₂ < 14 and T₂ within 1–5 ms was 7.95%, which was close to the proportion of asphaltene in the oil (8.95%) calculated using the four-component analysis method. This indicates that the corresponding part of the T₁-T₂ atlas is asphaltene, which is consistent with the findings of Han et al.³⁶.

Fig. 9.

T₁-T₂ map of oil and deposited asphaltene.

Figures 10A and 11A, and 12A show a T₁-T₂ map of the three cores before CO₂ flooding. The asphaltene signals were extracted from the spectral signals (i.e., 1 ms < T₂ < 5 ms and 5 < T₁/T₂ < 14 from Figs. 10B and 11B, and 12B). The asphaltene contents of cores 6–10, 3 − 1, and 6–31 were 7.52%, 7.77%, and 7.82%, respectively, indicating a similar asphaltene content of the three cores before core flooding. Figures 13A and 14A, and 15 A show the T₁-T₂ map of the three cores after CO₂ flooding. Asphaltene signals were extracted from the atlas signals (1 ms < T₂ < 5 ms and 5 < T₁/T₂ < 14; from Figs. 13B and 14B, and 15B). The results show that the proportions of asphaltene in the 6–10 (5 MPa), 3 − 1 (15 MPa), and 6–31 (25 MPa) cores under different injection pressures were 8.42%, 9.04%, and 11.78%, respectively, indicating that with an increase in the injection pressure, the asphaltene content increases. The relative depositions (ratio of the asphalt mass deposited after CO₂ flooding to the asphalt mass in the oil before CO₂ flooding) of asphaltene in the core were calculated to be 11.97%, 16.34%, and 50.64%, respectively, as shown in Table 2. In the immiscible phase (5 MPa), the relative amount of asphaltene deposition was the lowest (11.97%), and as the experimental pressure gradually increased to a pressure greater than the minimum miscible pressure (injection pressure of 25 MPa), the extraction capacity of CO₂ was greatly enhanced. A large number of light (C₁–C₇) and intermediate (C₇–C₂₀) components were extracted from the oil, which increased the proportion of heavy components in the oil, reduced the solubility of asphaltene in the oil, and resulted in the mass deposition of asphaltene. Although permeability varies (0.374–0.758 mD), asphaltene deposition correlates weakly with it due to: Pore-Throat Size Selectivity: Asphaltene aggregates (5–20 nm) primarily block mesopores (2–50 nm), whose density is similar across cores (SEM imaging confirms uniform mesopore volume). Permeability differences arise from macropore connectivity rather than mesopore structure. Critical Deposition Threshold: Once asphaltene saturation exceeds 8–9%, further deposition forms rigid pore-lining films (AFM adhesion force > 50 nN), decoupling permeability loss from absolute deposition amount.

Fig. 10.

T₁-T₂ map of before core(6–10) flooding.

Fig. 11.

T₁-T₂ map of before core(3 − 1) flooding.

Fig. 12.

T₁-T₂ map of before core(6–31) flooding.

Fig. 13.

T₁-T₂ map of saturated again core(6–10) flooding.

Fig. 14.

T₁-T₂ map of saturated again core(3 − 1) flooding.

Table 2.

Results of displaced asphaltene deposition.

Sample number	Porosity /%	Permeability /mD	Asphaltene content/%	After flooding	Relative deposition /%	Injection pressure /MPa
			Before flooding
6–10	12.396	0.504	7.52	8.42	11.97	5
3–1	11.498	0.758	7.77	9.04	16.34	15
6–31	10.226	0.374	7.82	11.78	50.64	25

Fig. 15.

T₁-T₂ map of saturated again core(6–31) flooding.

Damage evaluation of asphaltene deposition

The ordinate of the Nuclear Magnetic Resonance (NMR) T₂ spectrum curve represents the signal amplitude of the fluid under investigation, which directly correlates with the fluid saturation levels within the core pores. We measured the T₂ spectrum curves in two distinct states: initially, when the core was fully saturated with oil prior to CO₂ displacement (without asphaltene precipitation damage), and subsequently, after CO₂ displacement (with asphaltene precipitation damage) when the core was again fully saturated with oil. Following CO₂ displacement, the asphaltene precipitates formed tend to deposit within the pores, partially obstructing them and preventing the re-saturated crude oil from accessing the pores that were previously saturated with oil. This manifests as a corresponding decrease in signal amplitude in the T₂ spectrum curve during the re-saturation process compared to the initial fully saturated state.

The abscissa of the NMR T₂ spectrum curve corresponds to the transverse relaxation time, which serves as an indicator of the pore size distribution in the fully saturated core. Previously, scholars have conventionally classified pores with transverse relaxation times T₂ < 1 ms as micropores, those with T₂ > 10 ms as macropores, and those with T₂ ranging from 1 to 10 ms as mesopores.

Figure 16 shows the NMR T₂ maps of the saturated oil before and after CO₂ flooding of the core. According to Eq. (3), the longer the transverse relaxation time T₂, the larger the corresponding pore radius. Previously, scholars usually regarded pores with a relaxation time of T₂ < 1 ms as micropores, pores with a relaxation time of T₂ > 10 ms as macropores, and pores between 1 and 10 ms as medium pores. By comparing the T₂ spectrum during re-saturation with that of the initial condition, it is evident that asphaltene is mostly deposited in the mesopores and macropores. The pore obstruction caused by asphaltene deposition prevents the resaturated crude oil from entering the pores, which lowers the T₂ spectrum curves by 1–10 and > 10 ms.

Fig. 16.

T₂ spectrum of cores.

The permeabilities K1 and K2 before and after CO₂ flooding were calculated using Eqs. (4) and (5) to further obtain the permeability reduction rate of the core (= 1-K2/K1, shown in Table 3). Simultaneously, the area enclosed by the T₂ spectrum curve and abscissa is related to the core gas porosity before CO₂ flooding and calculates the core porosity and porosity reduction rate after CO₂ flooding (Table 3). As shown in Figs. 17 and 18, with an increase in experimental pressure, the damage rate of asphaltene to permeability during CO₂ flooding increased from 23.29 to 65.25%, and the reduction rate to porosity increased from 5.91 to 17.36%. The damage degree of the middle hole increases monotonically with the pressure, and the growth rate accelerates after 20 MPa. The damage degree of large pores (> 50 nm, black curve) reaches a peak value (~ 0.12) at 15 MPa, and then decreases to 0.08 at 20–25 MPa. The reason is that at the low pressure stage (< 15 MPa), injected CO₂ preferentially enters the macropore, and its high flow rate and low capillary resistance lead to rapid deposition of asphaltene at the macropore throat through shear detachment and sudden solubility. Asphaltene bridge in the macropore reduces the scour effect of fluid on the mesoporous area, and the damage degree in the mesoporous area decreases. When the pressure is > 15 MPa, the CO₂ diffusion coefficient is increased by 2–3 times, and the asphaltene nanoaggregates invade the mesopore throat, forming a size-matching blockage. The degree of reduction to the permeability and porosity of the asphaltene was directly proportional to the amount of asphaltene deposited, The conclusions obtained in this study are consistent with the research results of Li, Yin and other scholars^37–40.

Table 3.

Analysis table of reduction results of CO₂ displaced asphalt deposition.

No.	Core No.(Injection pressure)	Physical parameters
		Before flooding		After flooding		reduction of Permeability /%	reduction of Porosity /%
		Permeability K1/mD	Porosity /%	Permeability K2/mD	Porosity /%
1	6–10 (5 MPa)	0.504	12.396	0.387	11.56	23.29	6.71
2	3 − 1 (15 MPa)	0.758	11.498	0.296	10.14	60.88	11.8
3	6–31 (25 MPa)	0.374	10.226	0.13	8.45	65.25	17.36

Fig. 17.

Physical properties reduction rate.

Fig. 18.

Porosity reduction rate.

By comparing the T₂ spectral curves of the three cores (at different injection pressures) before and after CO₂ flooding, the T₂ spectral curves exhibited varying degrees of decline after CO₂ flooding at different injection pressures. When the injection pressure was 5 MPa, the amplitude of the NMR T₂ spectrum of the saturated oil after CO₂ flooding changed slightly compared to the distribution characteristics of the oil before CO₂ flooding, and the change was mainly detected in the macroporous part. This slight change indicates that less asphaltene was deposited after CO₂ flooding, and the reduction rate to the permeability and porosity was the smallest. When CO₂ and oil reached near miscibility (15 MPa), the T₂ spectrum curve decreased after CO₂ flooding, and the corresponding T₂ spectrum amplitude of mesopores and macropores decreased significantly.

Before the oil phase comes into contact with CO₂, asphaltene particles in crude oil aggregate under the action of hydrogen bonds and acid groups to form the core of colloidal micelles, which are then encapsulated by resins on the outside, homogeneously dispersed in the crude oil system in the form of micelles^41,42. When CO₂ is injected into and dissolved in crude oil, smaller CO₂ molecules gradually replace the adsorption space occupied by resins, leading to desorption of resins from the surface of asphaltenes. This disrupts the equilibrium state and results in asphaltene precipitation⁴³.

As the injection pressure of CO₂ gradually increases, transitioning from non-miscible displacement to miscible displacement by raising the pressure, the solubility of CO₂ in crude oil continues to increase, causing significant asphaltene precipitation. Furthermore, after CO₂ and crude oil become miscible, their extraction and extraction capabilities are greatly enhanced. Light components in crude oil enter the CO₂ phase, increasing the proportion of heavy components, further disrupting the equilibrium state and accelerating asphaltene precipitation.CO₂ can effectively employ oil in pores of all types (including small pores) during miscible flooding, while on the other hand, it also causes asphaltene deposition in pores at all levels, further reducing porosity and permeability. Therefore, in the process of near-miscible and miscible floodings, the reservoir produces a large amount of asphaltene deposition, causing damage to the reservoir.

Asphaltene deposition damage and prevention in reservoir

Asphaltene deposition damage in reservoir

In the course of development, asphaltene precipitation resulting from CO₂ flooding impacts the overall oilfield development in multiple ways. Notably, the influence of asphaltene deposition on reservoir properties is significant, and this impact exhibits variability across reservoirs with different pore structures. Specifically, the precipitation and adsorption behavior of asphaltenes in reservoirs, as well as their pore-blocking effects, are constrained by the characteristics of reservoir pore structures. In low-permeability oilfields, where pore throat connections are narrow and fluid flow capacity is inherently limited, extensive asphaltene deposition and precipitation can readily lead to plugging of these narrow throat connections, further restricting fluid flow.

Furthermore, during CO₂ flooding development, the impact of asphaltene deposition on profile modification cannot be overlooked. Asphaltene deposition within the CO₂ sweep zone reduces reservoir permeability, thereby weakening the flow capacity of CO₂ in high-permeability zones and along main streamline directions, demonstrating a certain potential for profile modification. However, the plugging caused by asphaltene deposition in actual formations exhibits uncertainty and instability. The uncertainty primarily stems from factors such as formation pressure and interactions between CO₂ and crude oil, which affect the amount of asphaltene precipitation, while pore structure characteristics determine whether asphaltene deposition will lead to plugging. The instability manifests as changes in formation pressure and fluid composition may cause already deposited asphaltenes to redissolve into crude oil, resulting in the potential for previously plugged pore throats to become unblocked at any time.

Additionally, the damage to reservoir permeability caused by asphaltene deposition is relatively limited, making it difficult to effectively achieve the expected profile modification effect. The deposition of asphaltenes in reservoirs also triggers pressure changes. Deposited asphaltenes reduce reservoir permeability, causing an additional pressure drop during fluid flow. In the near-wellbore region, asphaltene deposition decreases the injection capacity of injector wells, necessitating an increase in injection pressure to maintain a certain steam injection rate. Near production wells, asphaltene deposition increases pressure losses in the near-wellbore area, which can easily lead to crude oil degassing and subsequently affect production capacity. Overall, asphaltene deposition in reservoirs generates additional pressure drops during fluid flow, increasing formation energy losses and reducing development efficiency.

Asphaltene prevention in reservoir

The deposition process of asphaltenes in crude oil can be meticulously divided into three stages: precipitation, flocculation, and deposition. During precipitation, changes in system temperature, pressure, or composition lead to the aggregation of asphaltenes, forming larger floccules. In the flocculation stage of asphaltenes, the positive charges carried by the floccules attract the negative charges on reservoir rocks due to lattice defects, resulting in the adsorption of asphaltene molecules onto the surface of reservoir rocks and consequently narrowing the seepage channels for crude oil flow. Therefore, the key to effectively preventing asphaltene precipitation in reservoirs lies in taking measures before the flocculation stage of asphaltenes to reduce their adsorption strength on the surface of reservoir rocks.

Asphaltene precipitation can occur at any stage of the petroleum production system, but its precipitation in the near-wellbore region has the greatest impact on subsequent production operations. If asphaltenes plug pores in the near-wellbore region, it will significantly increase the difficulty and cost of remediation operations, making it particularly crucial to inhibit asphaltene precipitation in this area⁴⁴. Currently, conventional methods for inhibiting asphaltene flocculation primarily include two approaches: one is the periodic use of solvent immersion during well workover operations, and the other is the continuous injection of chemical inhibitors into the wellbore⁴⁵. Although these measures have achieved certain effects in preventing the formation of lumps and deposition of asphaltenes in production pipelines and tubing, they exhibit significant deficiencies in protecting the producing formations. This is because these chemical inhibitors typically interact with asphaltenes only after the crude oil leaves the formation, potentially allowing some asphaltenes to remain trapped within the formation.

To address this issue, a more practical method currently in use is to add asphaltene inhibitors while the crude oil is still in the formation. This method requires the injection of asphaltene precipitation inhibitors into the formation to stabilize the asphaltenes before flocculation occurs⁴⁶. However, test results indicate that inhibitors alone are difficult to produce long-term effects due to the insufficient absorption capacity of the formation for inhibitors, leading to their rapid release from the formation during crude oil production⁴⁷. On this basis, a pretreatment of the formation with activators can be employed to enhance the formation’s absorption capacity for inhibitors without altering its wettability.

Conclusions

1. Under reservoir conditions, the extraction of the four oil components under different injected CO₂ volumes showed that asphaltene deposition increases with an increase in CO₂ injection. When the molar ratio of injected CO₂ to oil is 9:5, the asphaltene deposition of the oil reaches a maximum, with a relative deposition of asphaltene of 86.70%.

2. In the process of CO₂ flooding, when CO₂ and oil are still in the immiscible phase, the relative deposition of asphaltene is 11.97%. As the experimental pressure increases gradually to a point greater than the minimum miscibility pressure, the extraction effect of CO₂ on the light and intermediate components in the oil increases gradually, leading to more asphaltene deposition, and the relative deposition amount of asphaltene increases up to 50.64%.

3. During CO₂ flooding, when CO₂ and oil are miscible, asphaltene deposition occurs in the pores at all levels. By comparing the T₂ spectrum during re-saturation with that of the initial condition, it is evident that asphaltene is mostly deposited in the mesopores and macropores. The reduction to the asphaltene deposition porosity reaches up to 17.36%, making the reduction to the permeability 65.25%.

​Practical guiding significance:

• Injection optimization: Adhere to the 9:5 CO₂/oil molar ratio as a safety threshold to minimize pore size damage in low-permeability reservoirs.

  Pressure regulation: Implement gradient pressure control to transition from immiscible to miscible to maximize oil recovery without triggering severe asphaltene deposition.

  Pore protection: Pre-washing is combined with nanoparticle inhibitors to preserve pore integrity and reduce permeability losses by 40–60% (validated by core flooding tests). These findings provide actionable guidelines for designing CO₂-EOR projects in heterogeneous reservoirs, ensuring economic viability while addressing the risk of formation damage.

Electronic supplementary material

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Author contributions

Zangyuan Wu is responsible for the preparation presentation of the published work, specifically writing the initial draft (including substantive translation), Qihong Feng is responsible for the preparation presentation of the published work by those from the original research group, specifically critical review, commentary and revision – including pre- and post-publication stages, Xiangjuan Meng is responsible for the management activities to annotate (produce metadata), scrub data and maintain research data (including software code, where it is necessary for interpreting the data itself) for initial use and later re-use, Daiyu Zhou is responsible for the application of statistical, athematical, computational, and other formal techniques to analyze and synthesize study data, Yongqiang Xu is responsible for the development or design of methodology, Gengping Yan is responsible for management and coordination responsibility for the research activity planning and execution, Jitian Ren and Qianrui Cheng are responsible for provision of study materials, laboratory samples, instrumentation, omputing resources, and other analysis tools, Wenlian Xiao is responsible for verifying the overall reproducibility of experiments and other research results.

Data availability

The data that support the findings of this study are available from the corresponding author, upon reasonable request.

Declarations

Competing interests

The authors declare no competing interests.