Effective Pore-Throat Sweep Limits and Microscopic Oil Mobilization during CO₂-WAG Flooding in Low-Permeability Conglomerate Reservoirs

1 Introduction

The tight structure, pronounced heterogeneity, low porosity, and low permeability of conglomerate reservoirs render conventional water flooding and gas flooding methods inefficient and difficult to implement effectively. Reservoir B, a representative conglomerate reservoir in the Junggar Basin, is characterized by poor petrophysical properties, strong heterogeneity, and high sensitivity. Its development performance has declined progressively in recent years, while the issue of ineffective water injection circulation has become increasingly prominent. The reservoir has entered a “double-high” development stage and urgently requires a transformation of the development strategy to further enhance the recovery factor.

CO2 injection is an effective approach for recovering substantial amounts of oil from low-permeability or tight reservoirs [1,2]. However, the sweep volume achieved during CO2 flooding has consistently remained a critical challenge. The unfavorable mobility ratio between CO2 and crude oil, mainly caused by the large viscosity contrast between the two phases, generally results in reduced sweep efficiency within the reservoir. In the absence of effective profile control, viscous fingering, channeling, premature CO2 breakthrough, and crude oil bypassing can further impair the macroscopic sweep efficiency of CO2 flooding, thereby significantly reducing both CO2 utilization and storage efficiency [3].

Controlling the unfavorable mobility ratio during gas injection to improve macroscopic sweep efficiency has long been a major research focus. CO2-WAG has been applied in heterogeneous reservoirs as an important zero-carbon or even carbon-negative technology for mitigating gas channeling and viscous fingering during CO2-enhanced oil recovery. For heterogeneous low-permeability reservoirs with complex seepage mechanisms, alternating CO2 and water injection (WAG) can regulate fluid flow at the displacement front to some extent and suppress gas viscous fingering, thereby improving CO2 sweep efficiency and enhancing flooding performance [4]. This technique combines the expanded sweep volume associated with water flooding and the high displacement efficiency of CO2 injection. In addition, WAG injection may promote bubble formation within the reservoir, creating high flow resistance in swept zones through the Jamin effect and diverting more displacing fluid into unswept regions, thereby further improving macroscopic sweep efficiency.

The water-alternating-gas (WAG) technique has progressively matured through laboratory physical simulation studies and field applications, and it is now recognized as one of the most effective enhanced oil recovery (EOR) methods for low-permeability reservoirs. Extensive research has been conducted on its principal design parameters and influencing factors, including gas–water ratio, number of WAG cycles, slug size, injection rate, oil–gas phase behavior, and gas type [5,6,7,8]. Fang et al. [9] reviewed recent advances in CO2-water-alternating-gas (CO2-WAG) technology for enhanced oil recovery, covering its theoretical basis, field applications, fluid displacement mechanisms, and control strategies. Abdurrahman et al. [10], focusing on the Sumatera Light Oilfield, performed numerical simulations of immiscible alternating CO2 and water injection and reported that a gas–water ratio of 1:2 was optimal, yielding an incremental recovery factor of 35.24%. When the gas–water ratios were 2:1 and 1:1, the additional recovery factors were 1.49% and 19.52%, respectively. Khather et al. [11] established residual oil saturation after water flooding under reservoir conditions and subsequently injected CO2 and reconstituted formation water alternately (0.5 pore volume CO2 and 0.5 pore volume water). Porosity, permeability, NMR T2 measurements, and X-ray CT scans were conducted before and after the experiment. The results showed that CO2-WAG significantly increased oil recovery by approximately 30% under the tested conditions. Zhang et al. [12] investigated the enhanced recovery mechanism of CO2-WAG through displacement experiments using cores with different permeability levels to simulate heterogeneous reservoirs. Nuclear magnetic resonance (NMR) technology was used to monitor the dynamic distribution of residual oil during displacement at multiple scales, including reservoir, layer, and pore scales. The effects of gas–water ratio and injection rate on multiscale recovery were also evaluated. CO2-WAG effectively suppressed early breakthrough in high-permeability layers, improved displacement efficiency in medium- and low-permeability layers, and enhanced microscopic displacement efficiency in medium and small pores. Al-Bayati et al. [13] evaluated the possible evolution of petrophysical properties in layered sandstone core samples during miscible CO2-WAG injection. Porosity and pore-size distribution were measured using NMR before and after water injection. Li et al. [14] found experimentally that CO2-WAG significantly altered the distribution of residual oil, and increasing the number of WAG cycles could further improve oil production. After water flooding, CO2 preferentially entered highly water-saturated pore throats and formed trapped gas, thereby reducing water production while increasing crude oil recovery. In that study, microfluidic visualization experiments were used to observe fluid flow behavior and residual oil mobilization in low-permeability reservoirs during alternating injection of CO2, water, and gas after water flooding. Sang et al. [15] proposed that CO2 injection reduced crude oil adhesion and interfacial tension, disrupted the oil–water equilibrium, and increased local displacement pressure, thereby improving the utilization of residual oil. With increasing WAG cycles, the productive pore-throat range remained within 8–30 μm, and residual oil displacement efficiency continued to improve, revealing the recovery mechanism of alternating CO2 and water flooding in low-permeability reservoirs. Liu et al. [16] combined core flooding experiments with NMR analysis to investigate the enhanced recovery mechanism of CO2-WAG at multiple scales, including reservoir, layer, and pore scales. The study compared sandstone and conglomerate reservoirs under miscible and immiscible conditions and analyzed the effects of gas–water ratio and injection rate. Under immiscible conditions, CO2-WAG achieved an oil recovery factor of approximately 22.95%, which was 7.82% higher than that of continuous CO2 flooding. This method effectively suppressed CO2 breakthrough in high-permeability layers while increasing recovery in medium- and low-permeability zones. As the gas–water ratio increased, total oil recovery also increased, together with improved recovery in low-permeability layers and micropores.

Xu et al. [17] combined NMR and CT techniques to study the microscopic distribution and displacement mechanism of residual oil during alternating CO2 and water injection in water-sensitive tight reservoirs. CO2 dispersed oil droplets, most of which were displaced from the pores, whereas water served as a mobility-control phase by blocking larger pores. However, due to water sensitivity, mesopores and micropores were also impaired, resulting in only marginal improvement from WAG following the initial CO2 flooding. Lang et al. [18] investigated factors influencing CO2 flooding in shale reservoirs through NMR experiments and analyzed the effects of soaking time, pressure, and temperature on CO2 flooding recovery based on NMR T2 spectra. Li et al. [19] conducted pore-scale simulations of WAG injection in water-wet porous media. The results showed that alternately injected water and gas preferentially swept the lower and upper regions of the porous medium, respectively, thereby increasing oil recovery compared with standalone water flooding or gas flooding. In particular, WAG processes ending with gas flooding showed considerable potential for both EOR and CO2 sequestration. For fixed injection cycles, increasing the volume of individual slugs further enhanced oil recovery. Using natural dense core samples from the Ordos Basin and high-precision NMR monitoring techniques, Zheng et al. [20] found that CO2-WAG increased flow resistance by 3 to 8 times compared with continuous displacement. Meanwhile, oil recovery increased by 5.1% to 9.0%, and sequestration efficiency improved by 4.3% to 5.6%. The combined CO2 utilization and storage coefficient reached its highest value, and the optimal segmented sequestration ratio was determined to be 1:1. Further analysis combined with MRI results indicated that during alternating CO2 and water injection, the injected water preferentially occupied dominant flow channels or fractures, thereby delaying gas breakthrough through the Jamin effect. Wang et al. [21] selected three representative conglomerate cores from different layers and conducted CO2 flooding and CO2-WAG flooding experiments using NMR technology. The results showed that immiscible CO2 flooding mainly displaced crude oil in large pores, whereas crude oil in micropores and mesopores was difficult to mobilize. After gas channeling occurred, extensive clusters of residual oil still remained in the cores, resulting in low recovery factors. He et al. [22] conducted long-core displacement experiments on CO2-WAG by adjusting alternating cycle size. NMR techniques were used to quantitatively characterize oil displacement performance under different microscopic pore structures. The results showed that during CO2-WAG flooding, cores with medium to high permeability exhibited higher recovery factors than those with medium to low permeability. CO2-WAG effectively mitigated gas channeling in medium- to high-permeability heterogeneous reservoirs. Wang et al. [23] conducted comparative experiments on CO2 flooding and alternating CO2-water flooding in the same multilayer system under miscible conditions (70°C, 18 MPa). After continuous CO2 flooding, the overall crude oil recovery factor was only 27.6%, with production mainly originating from the high-permeability layer, while the remaining oil was largely retained in medium- and low-permeability layers. In contrast, CO2-WAG required higher injection pressure but delayed CO2 breakthrough, and the total recovery factor increased to 44.5%. The contribution rates of the medium- and low-permeability layers to oil production increased to 3.8% and 17.1%, respectively. Through microscopic experiments, Qin et al. [4] found that the presence of gas in large pores altered the flow path of water during the second water-flooding cycle. Consequently, the enlarged sweep volume combined with favorable microscopic displacement efficiency demonstrated the high effectiveness of CO2-WAG injection.

The results of relevant studies on oil displacement efficiency and lower limit of effectively swept pore throats in low-permeability reservoirs seem insufficient. Studies generally suggest that alternating cycles and gas-water ratio are key parameters for optimizing the WAG effect. Therefore, in view of the high water cut, low permeability and strong heterogeneity of the ultra-low permeability of the conglomerate reservoir in oilfield B, this paper used an indoor long core experimental setup and on-site retrieved actual core splicing to simulate multiple sets of comparative experiments of continuous gas flooding and different alternating cycles and different gas-water ratio of CO2-WAG under formation temperature of 58°C and formation pressure of 20.1 MPa in B reservoir, The oil displacement effect and mechanism of CO2-WAG were studied, and the injection parameters for CO2-WAG flooding were optimized to provide a technical basis for its field application in the target reservoir. In addition, there is a lack of in-situ and quantitative understanding of how CO2-WAG utilizes crude oil from the denser micropores (especially nanoscale pores) in low-permeability reservoirs. For the KS group core, the lower limit of effectively swept pore throats was calibrated through online nuclear magnetic resonance experiments, and the synergistic mechanism of WAG was revealed.

2 Experimental Equipment, Materials and Methods

2.1 Core Displacement Experiments

2.1.1 Experimental Equipment

As shown in Fig. 1, the CO2-water alternating displacement system comprises an injection pump, a back-pressure regulator (BPR), three intermediate containers (for oil, gas and water, respectively), a core holder, a back pressure regulator, an oil-gas water separator and a metering device. The upper limit of working pressure for the displacement system is 70 MPa. The core holder and three intermediate containers are located in the oven. High-pressure stainless steel core holders are used to hold the core samples, which are mounted in the center of the core holder via rubber sleeves. Use three piston cylinders to store the experimental fluids (oil, water, and CO2). During the experiment, the fluid was injected into the core through a steel pipeline by a dual-plunger pump, and the injection pressure was measured by a pressure gauge installed at the inlet of the core holder. Set the confining pressure to prevent the experimental fluid from flowing around the core. Confining pressure was applied to prevent fluid bypassing the core sample. Additionally, a back pressure regulator (BPR) was installed at the outlet of the core holder to maintain the preset experimental pressure. The produced oil and water are collected in an oil-water separator.

Figure 1: The sketch of CO₂-WAG flooding system.

2.1.2 Experimental Materials

• (1)Reservoir fluids

The crude oil was obtained from the KS formation oil reservoir of B Oilfield in the Ordos Basin. The MMP for the reservoir fluid and CO2 was determined to be 18.5 MPa via slim tube experiments. The original formation pressure of the oil reservoir was 20.1 MPa, the pressure coefficient was 1.06, the temperature in the middle of the oil layer was 58°C, and the saturation pressure was 15.4 MPa. The original dissolved gas-oil ratio is 87 m3/m3 and the volume coefficient is 1.211. Formation crude oil viscosity 1.86 mPa·s density 0.768 g/cm3. Surface crude oil has a density of 0.8379 g/cm3, a pour point of 10.9°C, and a wax content of 7.6 percent. Specific gravity of associated natural gas 0.7893. Formation water type NaHCO3, total dissolved solids: 3574–6810 mg/L. The purity of the CO2 used in the experiment was 99.99%.

• (2)Core samples

Three cores with a diameter of 3.8 cm from the KS reservoir were selected and connected in series, with a length of 19.237 cm after splicing (Fig. 2). Filter paper was used to connect the end faces of the shorter cores. The average permeability of the core was 4.22 mD. The cores with the permeability closest to the average were placed in sequence near the outlet end, and the core parameters are shown in Table 1.

Figure 2: Core of the KS formation in the conglomerate reservoir.

2.1.3 Experimental Methods

The experimental steps for continuous CO2 displacement and gas-water alternating displacement are as follows:

• (1)Preparation of the experimental fluid:

After sampling the oil and gas samples from the surface separator in oilfield B, they were miscible and thoroughly stirred and balanced (~4 h) under formation temperature and pressure to make the fluid mixture a single-phase fluid.

• (2)Core preparation:

Prepare the long core holder, load the cores into the long core holder in the required sequence, calibrate, clean and dry the instrument, test the temperature and pressure, then evacuate and bring it to 58°C.

• (3)Saturated formation water:

Control the inlet pump to inject the reconstituted formation water into the long core, establish the system pressure of the long core to the formation pressure of 20.1 MPa, record the pump value, and calculate the saturated water volume of each long core.

• (4)Establish the irreducible water saturation and the original formation conditions:

Use live oil to replace the formation water to establish the irreducible water saturation of the long core. When the gas-oil ratio at the outlet end is consistent with the sample preparation, the original formation conditions are established, and then aging is carried out.

• (5)Water flooding:

Inject formation water at 0.1 mL/min at the inlet end and record the oil and water production at the outlet end.

• (6)(6.1) Pure CO2 flooding:

After water flooding to a Water cut >95%, inject CO2 at 0.1 mL/min until no oil is produced or only gas is produced. Record the oil production, water production and gas production, and calculate the flooding efficiency.

(6.2) CO2-water alternate flooding:

Carry out CO2-water alternate flooding after water flooding to a Water cut >95%. When exploring the influence of cycle, the total injection volume for each alternate round is designed to remain constant at 2 PV, and 1 to 5 cycles of displacement experiments are carried out at a gas-water ratio of 1:1. When exploring the influence of gas-water ratio, the total injection volume of CO2 was maintained at 1 PV, and the gas-water ratio range was designed to be 2:1 to 1:2. CO2 and water slugs were injected alternately at 0.1 mL/min until no oil was produced/only gas was produced. Record the production of oil and water, and calculate the oil displacement efficiency. Experimental protocols are shown in Table 2 and Table 3.

• (7)Cleaning the core:

After the experiment, the core was cleaned with petroleum ether and anhydrous alcohol. The petroleum ether was mainly used to clean the oil in the core, and the anhydrous alcohol was used to clean the water in the core. After cleaning, repeat steps (1)–(5) to form the original state for the next set of experiments.

2.2 Online Nuclear Magnetic Resonance Experiments

2.2.1 Laboratory Equipment

Through nuclear magnetic resonance relaxation analysis, the variation patterns of reservoir seepage characteristics under formation temperature and pressure conditions can be studied. As show in Fig. 3, the specification of the equipment is Niumag MacroMR12-150H-I. Magnetic field intensity 0.3 T, pulse frequency 1 to 30 MHz, frequency control accuracy up to 0.1 Hz, pulse accuracy 100 ns. The radio frequency has a maximum sampling bandwidth of 2000 KHz. The minimum echo time for a 1.5-inch core is 200 μs.

Figure 3: Online nuclear magnetic resonance displacement experimental apparatus.

2.2.2 Experimental Materials

The nuclear magnetic displacement experiment used the 9# core of the KS formation (Fig. 4), with a formation depth of 1931.97 m, a length of 72.12 mm, a diameter of 38.42 mm, a porosity of 10.43%, and a permeability of 3.10 mD. The injected water was a 6% mass fraction of manganese chloride solution. This causes the water signal to be shielded during the MRI scan, allowing only the detecting only the residual oil signal, thus making the results more accurate.

Figure 4: Conglomerate core from the online NMR experiment.

2.2.3 Experimental Methods

• (1)Core pretreatment:

Oil washing and drying of tight reservoir cores sampled on-site;

• (2)Saturated compound oil:

Place the core in an intermediate container, then vacuum for 48 h, and saturate the compound oil in the intermediate container for 48 h to saturate the crude oil into the throat of the tight reservoir core;

• (3)T2 spectrum of saturated oil state core:

Remove the core from the intermediate container and test the NMR T2 spectrum in the saturated oil state;

• (4)Water displacement T2:

Place the conglomerate core in the core holder of the set displacement system at a temperature of 58°C, and apply back pressure to the end of the core holder to a formation pressure of 20.1 MPa. Water is injected into the core holder at a constant rate of 0.1 mL/min. The confining pressure of the core holder is always 2.0 MPa higher than the pressure at the injection end. Water is injected for displacement until no oil is produced.

• (5)CO2 continuous displacement T2 spectra:

Insert the conglomerate core into the core holder in the established displacement system, set the temperature at 58°C, and apply back pressure to the end of the core holder to the formation pressure of 20.1 MPa. CO2 gas was injected into the core holder at a constant rate of 0.1 mL/min. The confining pressure of the core holder was always 2.0 MPa higher than the pressure at the injection end until the oil volume recorded in the graduated cylinder at the end of the core no longer increased, and the displacement experiment was concluded. Test the nuclear magnetic resonance T2 spectra under different continuous CO2 displacement states;

• (6)Replace the displacement medium:

Use a constant injection rate of 0.1 mL/min to alternately inject CO2 and water slugs of a 1:1 gas-water ratio into the core holder to replace crude oil in the core of the gravel reservoir, and repeat steps (2) to (5);

• (7)Data processing:

Convert the NMR T2 spectrum into the pore throat distribution to characterize the crude oil usage in pore throats of different sizes. The relationship between the T2 value of the fluid in the rock pores and the pore diameter can be expressed as: T2=Cr(1) C=1/ρF(2) here, ρ represents the surface relaxation rate of the rock core, and F is the pore shape factor. The surface relaxation rate is obtained from the data of high-pressure mercury porosimetry.

3 Core Displacement Experiments with Different CO₂ Injection Methods under Formation Conditions

• (1)Continuous CO2 displacement and CO2-WAG displacement in different cycles

To see how the number of alternating cycles affects the CO2-WAG performance, displacement experiments were run on the KS group core with 1 to 5 cycles. Fig. 5, Fig. 6, Fig. 7, Fig. 8, Fig. 9 and Fig. 10 show the results of experiments using cores from the KS group. The injection rate was kept constant at 0.1 mL/min. A gas-water ratio of 1:1 was used. The changes in oil displacement efficiency, water cut, and gas-oil ratio over time were recorded. The changes in oil production, water production, and gas production with injected pore volume were also measured. These experiments simulated reservoir formation conditions at 20.1 MPa and 58°C. Waterflooding was performed until the water cut went above 95%. After that, CO2 was injected. This step clearly raised the oil displacement efficiency. The error bars in the figures show a data error of 3%. The irreducible water saturation was 36.3%. The water cut reached 95% at 1 PV. At that point, the oil displacement efficiency was 41.30%. Then continuous CO2 displacement was carried out. Gas broke through at 1.27 PV. The cumulative oil displacement efficiency at breakthrough was 43.78%. Gas injection was continued to 2.03 PV. Then the oil recovery efficiency became stable. The final oil displacement efficiency after gas flooding reached 60.05%. This value was 18.75% higher than the value after water flooding. The gas-oil ratio at the end was 6454 m3/m3. The experimental results confirmed that CO2 flooding has a clear potential for enhanced oil recovery. However, the high gas-oil ratio also pointed to a tendency for gas channeling. The injection strategy needs more work to improve sweep efficiency. To assess the potential formation damage caused by CO2-WAG injection, the permeability of the long cores was remeasured after the experiments. Results indicated no significant formation damage; instead, the average permeability slightly increased by approximately 5%. This phenomenon is likely attributed to the dissolution of carbonate cementing materials by carbonic acid generated during the CO2 flooding process.

Figure 5: Water cut of KS core under continuous CO₂ flooding and different WAG cycles.

Figure 6: Cumulative oil production of KS core under continuous CO₂ flooding and different WAG cycles.

Figure 7: Cumulative water production of KS core under continuous CO₂ flooding and different WAG cycles.

Figure 8: Gas-oil ratio of KS core under continuous CO₂ flooding and different WAG cycles.

Figure 9: Oil displacement efficiency of KS core under continuous CO₂ flooding and different WAG cycles.

Figure 10: Differential pressure of KS core under continuous CO₂ flooding and different WAG cycles.

Experimental results shown in Fig. 11 indicate that the injection cycles have a significant regulatory effect on oil displacement efficiency. As the number of alternating cycles increased from 1 to 5, the final oil displacement efficiency of WAG gradually rose from 61.1% to 66.08%, and the increase compared to water flooding (oil displacement efficiency 41.3%) rose from 20.10% to 25.08%. The later the gas breakthrough time, the more the three phases of oil, gas and water come into full contact, which increases the oil-phase mobility ratio and reduces the viscosity of crude oil. When the injection cycles are 1 to 2, an increase in the single injection volume can easily cause CO2 channeling, resulting in a decrease in oil displacement efficiency. When there are 4 to 5 injection cycles, the injection slug is smaller, the contact between CO2 and crude oil is less, and the gas dissolution is smaller, which affects the development effect of the injection. Overall, three alternating cycles are the optimal parameters under the experimental conditions.

Figure 11: Enhancement of oil displacement efficiency by different CO₂-WAG cycle after water flooding.

• (2)Experiments on CO2-WAG displacement with different gas-water ratio

To study how the gas-water ratio affects CO2 water-alternating-gas displacement, the injection volume ratio of CO2 to water was changed. The ratios were set to 2:1, 1.5:1, 1:1, 1:1.5, and 1:2. Four cycles of gas-water alternating displacement were used for each ratio. Oil displacement efficiency, water cut, and gas-oil ratio were measured. Oil production, water production, and gas production were also recorded. Fig. 12, Fig. 13, Fig. 14, Fig. 15, Fig. 16 and Fig. 17 clearly show that the gas-water ratio has a large effect on the final oil displacement efficiency of the WAG process. As the gas-water ratio went down from 2:1 to 1:2, the final oil displacement efficiency of CO2-water alternating flooding went up from 62.03% to 66.95%. The increase compared to water flooding grew from 21.13% to 25.45%. A lower gas-water ratio helps crude oil and CO2 contact each other more fully. It also lowers the crude oil viscosity and delays the gas breakthrough time. A gas-water ratio of 1:2 raises oil displacement efficiency by 6.90% compared to continuous gas flooding. Notably, as the gas-water ratio goes up, the total injected pore volume increases. This increase leads to better displacement efficiency. When the gas-water ratio drops to 1:1 or below, the increase in oil displacement efficiency becomes smaller and slows down. This behavior comes from how the displacement phase controls fluidity and how the microscopic oil washing works under different gas-water ratios. A lower gas-water ratio means a higher proportion of water. This extra water helps control the flow of CO2 and suppress gas channeling. As a result, the macroscopic sweep efficiency improves. However, a very high water ratio may also weaken the mass transfer and extraction between CO2 and the crude oil underground. This weakening limits the gain in microscopic displacement efficiency.

Figure 12: Water cut of KS core with different gas-water ratios.

Figure 13: Cumulative oil production of KS core with different gas-water ratios.

Figure 14: Cumulative water production of KS core with different gas-water ratios.

Figure 15: Gas-oil ratio of KS core with different gas-water ratios.

Figure 16: Oil displacement efficiency of KS core with different gas-water ratios.

Figure 17: Differential pressure of KS core with different gas-water ratios.

As shown in Fig. 18, a gas-water ratio of 1:1 is an optimal injection parameter for the 9# core. It can form an effective CO2 enrichment zone, fully reduce the viscosity and interfacial tension of crude oil, and control the flow rate of CO2 through the water slug, allowing it sufficient time to diffuse into the micro-nano pore throat to interact with crude oil, thereby achieving a synergistic effect of macroscopic sweep and microscopic displacement.

Figure 18: Enhancement of oil displacement efficiency by different gas-water ratio after water flooding.

• (3)Error analysis and reliability

To ensure the reliability of the experimental results presented in Section 1 and Section 2, we systematically evaluated potential sources of error across all eleven experimental scenarios: continuous CO2 flooding, CO2-WAG flooding at five different cycle numbers (1 to 5 cycles), and CO2-WAG flooding at five different gas-water ratios (2:1, 1.5:1, 1:1, 1:1.5, and 1:2). The error analysis addresses experimental reproducibility, systematic and random errors, lithological modification during successive runs, and the quantified precision of the measurements.

• ①Systematic and Random Errors [24,25]: The pressure transducers employed for monitoring injection pressure, confining pressure, and differential pressure were calibrated prior to each experimental run. Liquid production was recorded using graduated cylinders, and readings were taken at regular intervals to minimize human reading errors. The injection pump was operated at a constant rate of 0.1 mL/min throughout all displacement experiments, and the back-pressure regulator maintained the outlet pressure at 20.1 MPa, consistent with the original reservoir formation pressure. At the pore scale, the Jamin effect—arising from gas bubble deformation as CO2 traverses complex pore throats in the conglomerate formation—introduces inherent fluctuations in the differential pressure profiles. These transient pressure variations represent an intrinsic feature of multiphase flow in low-permeability porous media and do not affect the overall displacement trends.

• ②Lithological Modification: During successive experimental runs, we observed a gradual increase in average permeability of approximately 5%. We attribute this to the dissolution of carbonate cementing materials by carbonic acid generated in situ when dissolved CO2 reacts with formation water under the experimental conditions of 20.1 MPa and 58°C. This permeability evolution is consistent with known geochemical interactions between CO2-enriched brine and carbonate-cemented clastic rocks, and it accounts for the minor differences observed between successive runs on the same long core.

• ③Quantified Precision: For the macroscopic production data—including oil displacement efficiency, water cut, gas-oil ratio, and cumulative oil, water, and gas production presented in Fig. 5, Fig. 6, Fig. 7, Fig. 8, Fig. 9 and Fig. 10 and Fig. 12, Fig. 13, Fig. 14, Fig. 15, Fig. 16 and Fig. 17—the error bars represent a relative error of 3%. The limited dispersion of the data across the eleven experimental groups confirms the reproducibility of the measurements and supports the validity of the optimized CO2-WAG injection parameters identified in this study.

4 Online Nuclear Magnetic Resonance Displacement Experiment

In this section, the dynamic changes of fluid signals in the core under different CO2 displacement methods were monitored in real time and in situ using online nuclear magnetic resonance technology, and the NMR transverse relaxation time (T2) were converted into pore throat distributions, thereby quantitatively revealing the crude oil displacement patterns in pores of different scales, clarifying the microscopic distribution characteristics of the remaining oil and the lower limit of effectively swept pore throats for different displacement methods.

• (1)Continuous CO2 gas flooding

Aiming at the problem of unclear effective pore range for CO2 flooding in Oilfield B, an online nuclear magnetic resonance experiment of converting water flooding to CO2 flooding in the KS group core was carried out at 20.1 MPa and 58°C. The online nuclear magnetic resonance experiments clearly demonstrated the displacement of pores by continuous CO2 flooding. As shown in Fig. 19, during the process of establishing the irreducible water saturation, the oil phase, as the non-wetting phase, preferentially enters the larger pores with less percolation resistance, and then enters the smaller pores. The T2 spectrum of the core exhibits a bimodal distribution with a higher right peak, indicating that the crude oil is primarily distributed within two pore throat size ranges: 10–100 nm (small pore throats) and 0.1–10 μm (large pore throats). The subsequent water flooding process led to a decline in both peaks of the T2 spectrum, but the decline in the right peak (the large pore throat) was much greater than that in the left peak (the small pore throat), indicating that the water flooding mainly utilized the crude oil in the large pore throat (>1 μm), with an effective pore lower limit of 18.2 nm. After continuous CO2 injection, as the injection volume reached 2 PV, the T2 spectrum pattern changed to “the bimodal peaks became comparable in height”, indicating that the crude oil signal in the small throat region was also significantly reduced. Quantitative analysis indicated that continuous CO2 flooding significantly expanded the lower limit of effectively swept pore throats from 18.2 nm after water flooding to 11.6 nm, and the upper limit of exploitation was 34.6 μm.

Continuous CO2 flooding can reach even smaller throats that water flooding cannot, and the core mechanism lies in the unique physicochemical effects of CO2. When CO2 gas is injected into the reservoir under high pressure, it dissolves rapidly in crude oil, causing the volume of crude oil to expand and significantly reducing the viscosity of crude oil, thereby greatly improving the fluidity of crude oil. At the same time, the mass transfer between CO2 and crude oil can extract the light components in crude oil, further improving the fluidity of crude oil. The synergy of these effects enables CO2, which has strong diffusion and permeation capabilities, to enter the micro-nanoscale pore throat network that the aqueous phase cannot effectively reach, overcoming greater capillary resistance and driving out the bound crude oil. However, continuous gas flooding is also prone to gas channeling due to unfavorable mobility ratio, and its macroscopic sweep efficiency is limited, with some pore throat areas still not effectively swept.

Figure 19: Online NMR experiment T₂ spectra of CO₂ flooding after water flooding of KS core.

• (2)Alternate water and gas flooding

Perform an online NMR experiment of alternating water and gas flooding on the same 9# core. As shown in Fig. 20, the left peak (representing the micropores) of the T2 spectrum after CO2-WAG displacement decreased to a lower level compared with the T2 spectra after water flooding and continuous CO2 flooding. The lower limit of effectively swept pore throats of CO2-WAG flooding extends further to 9.52 nm. At the microscale, it also outperforms continuous CO2 flooding in terms of its ability to mobilize reservoir pore structures, especially for the remaining oil in nanoscale pore throats. The injection of water slugs effectively controls CO2 mobility, mitigating viscous fingering and premature gas channeling. This forces the injected CO2 to divert into unswept regions of medium-to-low permeability. Furthermore, water slugs introduce the Jamin effect by plugging preferential flow paths, increasing flow resistance and enhancing macroscopic sweep efficiency.

Figure 20: Online NMR experiment T₂ spectra of water and gas alternating flooding after water flooding of KS core.

The experimental results elucidate a distinct scale effect governing the multiphase flow mechanisms in low-permeability conglomerate reservoirs. At the microscopic scale, Nuclear Magnetic Resonance (NMR) analysis indicates that the Gas-WAG process significantly enhances the mobilization of residual oil within small pores (<100 nm). This phenomenon is primarily attributed to the microscopic Jamin effect, where the deformation of gas bubbles as they traverse pore throats generates fluctuating capillary pressures. These transient pressure variations are sufficient to overcome the adhesive forces binding the oil films to the pore walls.

However, at the macroscopic scale, this microscopic interaction manifests as a complex nonlinear increase in the pressure gradient. The alternating injection of immiscible phases (gas and water) induces severe phase interference, leading to a transient reduction in effective permeability. This behavior is quantitatively reflected in the relative permeability curves, characterized by a noticeable shift in the crossover point and a widening of the two-phase flow region. Consequently, the interplay between microscopic pore-scale mobilization and macroscopic fluid dynamic resistance dictates the overall displacement efficiency.

5 Conclusion

• (1)In the low-permeability reservoir of the KS formation, the waterflooding development effect was limited. The final oil displacement efficiency was 41.3%, and the water cut rose above 95%, indicating that the water flooding sweep efficiency was limited and it was difficult to further improve the oil displacement efficiency. Online nuclear magnetic resonance shows that water flooding mainly recovers crude oil in macropores, with a lower limit of effectively swept pore throats of 18.2 nm. Crude oil in a large number of small pore throats (micro-nano pore throats <100 nm) is difficult to drive effectively and becomes the main space for remaining oil accumulation.
• (2)Continuous CO2 flooding can significantly improve flooding efficiency, but there is an obvious risk of gas channeling. Compared with water flooding, continuous CO2 flooding increases oil displacement efficiency by 18.75%, but the gas-oil ratio rises rapidly during extraction, indicating significant gas channeling and the need for improvement in sweep efficiency. Compared with water flooding, continuous CO2 flooding extends the lower limit of effectively swept pore throats from 18.2 nm to 11.6 nm, demonstrating that CO2 can effectively drive the remaining oil in smaller micropores after reducing crude oil viscosity and interfacial tension. But the problem of its macroscopic sweep restricts the overall effect.
• (3)The CO2-water alternation drive is the best development approach in terms of overall effect, achieving the synergy of macroscopic sweep and microscopic displacement. The oil displacement efficiency increases with the number of alternating cycles, but slows down after more than three cycles. The oil displacement efficiency increases as the Gas-water ratio decreases, but the increase decreases below 1:1. The optimal injection parameters for CO2-WAG injection are a 1:1 Gas-water ratio and three alternating cycles. Under this scheme, the final oil displacement efficiency can reach over 66%, which is 25% higher than that of water flooding and 5% higher than that of continuous gas flooding, and it can control the gas-oil ratio more effectively and suppress gas channeling. Online nuclear magnetic resonance experiments confirmed that under the WAG scheme, the lower limit of effectively swept pore throats of the KS conglomerate core was further extended to 9.52 nm, clearly revealing the superiority of gas-water alternating flooding over continuous gas flooding in micro-activation capacity. The water slug controls flow and expands macroscopic sweep, while the CO2 slug reduces viscosity and extracts, and drives micropores. The two alternate and work together to break through the limitations of a single displacement method. Therefore, CO2 gas-water alternating flooding can serve as an effective method for late-stage channeling prevention and enhanced oil recovery in high-water-cut and low-permeability reservoirs.