In this section, the basic parameters such as dissolution gas-oil ratio, volume factor, and gas-containing crude oil viscosity of three gases N₂, CH₄, and CO₂ were tested using destination block crude oil.

(1) Experimental materials and device. To meet the requirements for the widespread application of gas injection techniques in mid-deep heavy oil reservoirs in Xinjiang, priority was given to selecting blocks with large reserves, typical reservoir characteristics, deep formation, and high viscosity. Following this principle, the crude oil sample from well W1 was chosen for the experiment. The injection gas were N₂, CH₄, CO₂, and the purity of the experimental gases was 99.999%. The experimental device used was the YRD-70/300 high-pressure physical property analyzer.

This section conducts a series of experiments to investigate the oil displacement efficiency of different gases, such as N₂, CH₄, and CO₂, under various conditions.

(1) Experimental materials. The experimental oil is heavy oil from well W1, with a viscosity of 256 mPa s at 50°C. The purity of the experimental gases is 99.999%. The experimental core is a 25 mm × 300 mm synthetic core, with specific parameters detailed in Table 1.

Repeated the above experimental steps to conduct N₂, CH₄, and CO₂ oil displacement experiments sequentially, obtaining the displacement efficiency for different injected gases.

In this section, three cycles of gas huff-n-puff physical simulation experiments using N₂, CH₄, and CO₂ were conducted with crude oil from well W1 to explore the mechanisms of enhanced oil recovery with different injection gases.

The gas huff-n-puff testing experiment utilized the same experimental materials and equipment as shown in Figure 1, with the sand-filled tube model having dimensions of 25 mm × 500 mm. The specific parameters of the core are detailed in Table 2.

The specific experimental steps are as follows:

1) Prepared the core holder model and measured the pore volume of the sand-filled tube.

Repeated the above experimental steps to conduct N₂, CH₄, and CO₂ oil displacement experiments, obtaining the displacement efficiency for different injected gases.

Through the experiment, the solubility, gas-containing crude oil viscosity, and volume factor of W1 well crude oil at 34°C under different pressure conditions with injected N₂, CH₄, and CO₂ were measured. The experimental results are displayed in Figure 2.

As shown in Figure 2A, under the condition of 34°C, the solubility of N₂, CH₄, and CO₂ gases in crude oil increases with the rise in saturation pressure. Among them, at the same pressure, the solubility of CO₂ is the highest, and that of N₂ is the lowest. Specifically, at a pressure of 15MPa, the solubility of CO₂ is 80.19 m³/m³, with a solubility coefficient of 5.346 (m³/m³)/MPa.

From Figure 2B, it is observed that at 34°C, the viscosity of crude oil dissolving N₂, CH₄, and CO₂ decreases with increasing saturation pressure. At the same pressure, the viscosity of crude oil with injected N₂ is the highest, while the crude oil with injected CO₂ has the lowest viscosity. At a pressure of 15MPa, the viscosity of crude oil with injected CO₂ is 49 mPa s, resulting in a viscosity reduction rate of 93.2%, and the CO₂ has the best viscosity-reducing effect.

As shown in Figure 2C, at 34°C, the crude oil volume factor for oil dissolving N₂, CH₄, and CO₂ increases with the rise in saturation pressure. Under the same pressure conditions, the volume factor of crude oil dissolving CO₂ is the highest, while that of N₂ is the lowest. Specifically, at a pressure of 15MPa, the volume factor for CO₂ is 1.23 m³/m³, with a shrinkage rate of 18.70%.

Through our experiments, we’ve made important discoveries regarding gas solubility, changes in crude oil viscosity, and the crude oil volume coefficient. The key findings of this study include:

The solubility of N₂, CH₄, and CO₂ in crude oil increased with rising saturation pressure. Notably, CO₂ exhibited the highest solubility among the three gases, underlining its superior potential for enhancing crude oil recovery in reservoirs. This is attributed to CO₂’s remarkable solubility coefficient of 5.346 (m³/m³)/MPa. At a pressure of 15 MPa, CO₂ achieved a solubility of 80.19 m³/m³, highlighting its effectiveness. The dissolution of these gases into crude oil led to a decrease in oil viscosity with increasing saturation pressure, a critical factor for boosting crude oil flowability and recovery efficiency. The marked viscosity reduction observed following CO₂ injection, with a rate of 93.2%, underscores the efficacy of CO₂ injection in enhancing the mobility of heavy oils. The crude oil volume coefficients after gas dissolution also rose with pressure. The increase was most pronounced for CO₂, suggesting that CO₂ not only improves the flow characteristics of crude oil within the reservoir but also significantly enhances the reservoir’s displacement efficiency.

This study highlights the distinct advantages of CO₂ injection in improving crude oil recovery by demonstrating its superior solubility, its ability to reduce crude oil viscosity effectively, and its impact on increasing the crude oil volume coefficient. These findings underscore the potential of CO₂ injection as a valuable technology for enhancing the recovery and mobility of crude oil, particularly in challenging reservoir conditions.

Using crude oil from well W1, physical simulation experiments of oil displacement under simulated reservoir conditions were conducted with injected N₂, CH₄, and CO₂. The results are shown in Figure 3.

As indicated in Figure 3A, under the same injection volume conditions, CO₂ injection achieved the highest oil displacement efficiency at 48.35%, followed by N₂ at 30.18%, and CH₄ at 30.07%. Figure 3B reveals that with the increase in the number of injected pore volumes (PV), the production pressure differential gradually increases. The peak production pressure differential in CH₄ injection is the highest, followed by CO₂, with N₂ being the lowest. Furthermore, the peak of the production pressure differential for CH₄ injection occurred the latest, indicating that the breakthrough timing of oil displacement by CH₄ injection is later than that of CO₂ and N₂ injections.

Analysis suggests that during the displacement processes with injected N₂, CH₄, and CO₂, due to the stronger solubility of CH₄ and CO₂ in crude oil under the same injection pressure compared to N₂, the gas breakthrough occurs earliest in N₂ injection, reaching the peak production pressure differential first. The partial dissolution of CH₄ and CO₂ gases results in the expansion of crude oil volume and a decrease in heavy oil viscosity, enhancing the fluidity of the crude oil. However, under experimental conditions, miscible flooding was not achieved after gas injection, and the flow rate is relatively high, which leads to gas breakthrough and consequently lower oil displacement efficiency.

Our experiments provided a thorough insight into how different gas injections—specifically N₂, CH₄, and CO₂—affect oil drive efficiency and production differential pressure. The findings highlight CO₂’s significant impact, enhancing oil driving efficiency to 48.35%, a substantial improvement over the 30.18% and 30.07% seen with N₂ and CH₄, respectively. This underscores CO₂’s critical role in bolstering oilfield recovery.

Furthermore, the observed trends in production differential pressure shed light on the distinct dynamics of gas-driven oil displacement. CH₄ injection, in particular, resulted in the highest and most delayed peak in production differential pressure, indicative of the prolonged crude oil breakthrough in the CH₄ displacement process. This variation largely stems from the gases’ solubility in crude oil and their influence on oil flowability. The superior solubility of CO₂ and CH₄ in crude oil, relative to N₂, leads to both an expansion in crude oil volume and a decrease in the viscosity of thick oil, thereby enhancing crude oil flowability. However, this also suggests a potential limitation in further optimizing oil drive efficiency.

Physical simulation experiments of gas huff-n-puff with N₂, CH₄, and CO₂ were conducted on W1 well crude oil, spanning three cycles, to explore the enhanced oil recovery effects and mechanisms of different media in different cycles. The experimental results are shown in Figure 4.

From the comparison of the three rounds of huff-n-puff results in Figure 4, it is evident that under the same injection volume conditions, CO₂ huff-n-puff yields a significantly higher oil recovery than CH₄ and N₂ huff-n-puff, indicating that the utilization rate of CO₂ huff-n-puff is greater than that of CH₄ and N₂. Due to the strongest solubility of CO₂, followed by CH₄, and the lowest for N₂, the N₂ huff-n-puff produces a larger volume of free gas and a longer initial gas production phase, contributing less to oil production. In contrast, the other two gases with higher solubility can form foam oil more effectively, aiding in gas dissolution and crude oil viscosity reduction, ultimately leading to better oil displacement results.

Referencing Figure 4D, after three rounds of injection, CO₂ injection yields the highest recovery rate at 44%, outpacing CH₄’s 35.5%, and significantly exceeding N₂’s modest 16%. This outcome, when juxtaposed with the data from Figure 3, reveals that repeated CO₂ injections result in a higher recovery rate than singular CO₂ drives. The latter approach, characterized by non-mixed-phase gas drive, tends to precipitate abrupt gas breakthroughs rather than facilitating a steady, uniform displacement of crude oil within the formation, thereby capping the potential for recovery rate enhancements.

Conversely, CO₂ injection as a repeated process allows for continuous reintroduction of CO₂ into the reservoir, ensuring thorough contact and integration with the heavy oil to create a foam oil. This strategy effectively circumvents the rapid gas breakthrough issue, enabling a more complete mixture of CO₂ with the oil and promoting a uniform CO₂ distribution throughout the reservoir. Such distribution enhances CO₂’s solubility in the heavy oil, broadly lowering the oil’s viscosity across the reservoir and thus improving oil mobility. Consequently, this method more effectively decreases the viscosity of the heavy oil and enhances its flow properties, leading to improved recovery rates.

Our experiments extensively examined the effects and mechanisms of different gases (CO₂, CH₄, and N₂) on enhancing oil recovery across three consecutive injection cycles. The data unequivocally demonstrate that CO₂ injection outperforms CH₄ and N₂ in terms of recovery efficiency under identical conditions. This superiority is primarily due to CO₂’s exceptional solubility in crude oil, which not only significantly reduces the oil’s viscosity but also facilitates the formation of foam oil, thereby improving oil displacement efficiency and lowering residual oil saturation.

N₂, with its minimal solubility, tends to produce a larger volume of free gas during injection, extending the initial phase of gas production and offering limited benefits to oil recovery enhancement. On the other hand, the greater solubility of CH₄ and CO₂ aids in foam oil formation, which, coupled with their ability to dissolve in crude oil and reduce its viscosity, substantially enhances the oil displacement effect. CO₂, in particular, stands out due to its superior solubility and capacity to decrease viscosity, effectively minimizing residual oil in the reservoir and significantly increasing crude oil recovery rates.

The model was established based on the basic geological reservoir parameters and well network parameters of the W1 well area. Two single-well groups were established: ① one with a vertical well for depletion production, ② one with a CO₂ huff-n-puff well group consisting of an injection well and a production well. In the CO₂ huff-n-puff well, it serves as an injection well during CO₂ injection and as a production well after the injection and soaking phases. In the vertical well CO₂ huff-n-puff simulation, each huff-n-puff round consisted of 15 days of gas injection, 10 days of soaking, followed by production with a fixed gas output after the soaking period. Each round had a production duration of 600 days, with a total of 4 rounds simulated over 2500 days. Specific parameters are detailed in Table 3. The objective layer is distributed with two interlayers, the thickness is 7 m and 1 m respectively, the permeability and oil saturation of the compartments were set to 0.01, and the permeability field is shown in Figure 5. The specific parameters of the reservoir in the target block are outlined in Table 3. In this table, the viscosity of the crude oil refers to the viscosity of degassed crude oil at 50°C. The subsurface condition is described as a single oil phase, and methane is noted as the dissolved gas within the parameters presented in Table 3.

(1) Single round CO₂ injection volume

In order to study the influence of single round injection volume on the effect of CO₂ huff-n-puff development, 100t, 200t, 400t, 600t, 800t and 1000t were simulated respectively, and the simulation results of CO₂ oil exchange rate and profit with different injection volumes are shown in Figure 6.

Numerical simulation results indicate that as the CO₂ injection volume increases, cumulative oil production gradually increases while the oil draining ratio decreases. At an oil price of $45, profits increase with the injection volume. The maximum profit growth rate is achieved at a single round injection volume of 200 tons of CO₂. Beyond 200 tons, the profit gradually decreases. The optimal injection volume is identified as 200 tons per well per round.

(2) Oil viscosity

To study the impact of crude oil viscosity on the effectiveness of CO₂ huff-n-puff, simulations were conducted at viscosities of 100 mPa s, 300 mPa s, 500 mPa s, 700 mPa s, and 900 mPa s. Results are shown in Figure 7. It is observed that as the viscosity of the crude oil increases, the cumulative oil production decreases and the total profit reduces, dropping to zero when the viscosity exceeds 500 mPa s. Therefore, it is recommended that vertical well CO₂ huff-n-puff is suitable for reservoirs with crude oil viscosity less than 500 mPa s.

(3) Reservoir permeability

To investigate the influence of formation permeability on CO₂ huff-n-puff development, simulations were carried out at permeabilities of 40 mD, 70 mD, 100 mD, 130 mD, and 160 mD.

The results, as shown in Figure 8, demonstrate that cumulative oil production and total profit increase with rising permeability. When permeability exceeds 100 mD, the total profit becomes positive, indicating that vertical well CO₂ huff-n-puff is suitable for reservoirs with permeability greater than 100 mD.

(4) Reservoir thickness

To assess the impact of reservoir thickness on CO₂ huff-n-puff development, simulations were performed at thicknesses of 6m, 8m, 10m, 12m, and 14 m. The results, depicted in Figure 9, show that as reservoir thickness increases, controlled reserves per well increase, leading to increased cumulative oil production and total profit. The profit turns positive when reservoir thickness exceeds 10m, suggesting that vertical well CO₂ huff-n-puff is suitable for reservoirs with a thickness greater than 10 m.

Two single-well group models for horizontal wells were established, one for depletion production and the other for CO₂ huff-n-puff, each with one injection well and one production well. The horizontal wells are located in the middle of the oil layer. The number of grids in the i×j×k direction is 21 × 21×34, and grid size in the i×j×k direction is 10 × 10 × 1 m. The other parameters and production regime for horizontal well CO₂ huff-n-puff are the same as for vertical wells.

(1) Single cycle CO₂ injection volume

Numerical simulation results (Figure 10) reveal that as the CO₂ injection volume increases, cumulative oil production increases, but the rate of increase in profit decreases. The maximum profit growth rate is achieved at a single cycle injection volume of 1000–1200 tons of CO₂.

(2) Crude oil viscosity

Simulations at viscosities of 100 mPa s, 300 mPa s, 500 mPa s, 700 mPa s, and 900 mPa s were conducted to study the effect of viscosity on horizontal well CO₂ huff-n-puff. The results (Figure 11) show a continuous decrease in cumulative oil production and total profit as viscosity increases, although the total profit remains positive. It is suggested that horizontal well CO₂ huff-n-puff is suitable for reservoirs with a viscosity less than 1000 mPa s.

(3) Reservoir permeability

Simulations at permeabilities of 10 mD, 40 mD, 70 mD, 100 mD, and 130 mD were performed to evaluate the impact on CO₂ huff-n-puff. The results (shown in Figure 12) indicate that as permeability increases, cumulative oil production and total profit also increase. Profits become positive when permeability exceeds 30 mD, suggesting suitability for reservoirs with permeability greater than 50 mD.

(4) Reservoir thickness

Simulations at thicknesses of 2m, 4m, 6m, 8m, 10 m were carried out to assess the impact on CO₂ huff-n-puff. The results (Figure 13) demonstrate that as reservoir thickness increases, controlled reserves per well increase, leading to increased cumulative.

The mechanism of foam oil formation through gas injection is pivotal for enhancing crude oil mobility and improving oil-gas contact efficiency. During the CO₂ huff-n-puff process, CO₂ mixes with heavy oil to form low-viscosity foam oil, which reduces the flow resistance of the oil and increases the oil recovery rate. In our in-depth numerical simulation study of the CO₂ huff-n-puff technique’s application in enhancing oilfield production, we identified injection volume, crude oil viscosity, reservoir permeability, and formation thickness as key parameters affecting the technique’s economic benefits and development outcomes. When considering the CO₂ huff-n-puff technique, it is crucial to take into account factors such as the reservoir’s crude oil viscosity, permeability, and formation thickness to devise the optimal development plan. These conditions not only influence the effectiveness of the technique but also directly impact the project’s economic viability.