Physical Simulation of Gas Injection Mechanism for High Dip Reservoir

Abstract

High dip angle reservoirs are affected by gravity, resulting in poor sweep performance at the middle and high parts during waterflooding development. Previous studies have proposed top gas injection development for this type of reservoir, which has provided direction for improving the development effect of such reservoirs. However, current research efforts have mainly focused on the analysis of gas injection effects, rather than delving deeper into the gas injection mechanism and its influencing factors. Furthermore, the research methods adopted thus far have been primarily theoretical and fail to take into account the typical characteristics of high dip reservoirs in actual oilfields. Using a similarity criterion, this study establishes a high-temperature and high-pressure physical simulation device with variable inclination to analyze the impact of gas injection under various water injection conditions on the development of high dip reservoirs. The results suggest that the earlier the injection of water and gas, the slower the overall increase in water cut, and the more distinct the oil wall effect after gas injection, leading to a higher ultimate recovery. In the experiments, earlier injection timing can increase the final recovery rate by 9.59%. In addition, a visualized physical simulation device with an adjustable inclination angle has been established to analyze the sweep performance of high dip reservoirs under various gas injection timings. It is concluded that energy supplement in the early stage of pressure decline in the reservoir resulted in a more uniform movement of the oil-water interface at the bottom and the oil-gas interface at the top, and reduced the probability of water and gas channeling. The overall displacement efficiency is found to be improved with this approach. Earlier injection timing increased sweep efficiency by 5.95% and recovery efficiency by 13.2%, respectively. The injection gas source determined in this study, which is associated gas, is beneficial for low carbon plan and exhibits satisfactory oil recovery. The development of high dip reservoirs through top gas injection in combination with bottom water injection can generate a synergistic effect, which significantly enhances sweep efficiency and ultimate oil recovery. This finding provides theoretical guidance for practical implementation in the field.

1. Introduction

As a development method to recover reservoir energy after depletion, gas flooding has been widely applied in specific types of reservoirs, including fractured reservoirs, sandstone reservoirs, and so on [1,2,3]. Although the application scale of gas flooding is not as extensive as that of water flooding, it has continued to increase in recent years, providing another choice for reservoirs with poor water flooding effect or low adaptability. Considering factors such as reservoir development effectiveness, cost, environmental protection, and low carbon emissions, the types of gas sources are also diversified, which has resulted in the evolution of various gas drive methods, including nitrogen drive, air drive, associated gas reinjection, and carbon dioxide drive and so on [4,5,6]. Among them, due to the increased focus on global climate change in recent years, Carbon Capture, Utilization and Storage (CCUS) has gradually emerged as a new priority, further improving the utilization scale and attention to gas drive as a secondary development method in reservoir production [7,8,9,10]. Similarly, the associated gas (methane-based hydrocarbon mixture) produced during reservoir production, in addition to power generation, heating, etc., for the oil field, the majority will be vented and burned, which will not only waste resources to some extent, but also increase carbon emissions and negatively impact goals around reducing global carbon emissions. The application of gas flooding has been successful in many reservoirs, and the recovery can be improved following the depletion, which is favorable for the overall development effect of the reservoir. However, the gas drive effect is closely related to the type of gas source, reservoir, and development conditions, and in the case of a limited range of gas source options, specific reservoir and development conditions will have a greater impact on the ultimate gas drive effect. Especially for high dip angle reservoirs, where the average inclination angle is greater than 15°, and the local area can reach more than 20°, the mechanism of associated gas flooding to enhance oil recovery is explored in the case of poor water flooding development effect (due to gravity, the injection water cannot sweep the middle and high parts of the reservoir) [11,12]. It is essential for this type of reservoir to achieve synergistic water and gas injection to improve oil recovery.

Due to gravity, gas injected into the reservoir flows in the upper part of the reservoir compared to water, and enters smaller pores, leading to higher oil displacement efficiency than that of water flooding. However, because the gas flow rate is faster than the water’s, gas channeling occurs frequently in reservoir development. Therefore, the success of gas flooding depends on choosing the appropriate reservoir type for gas injection. Currently, the scale of application in fractured reservoirs, low-ultra low permeability, tight oil and other reservoirs is progressively expanding, which is the result of the successful use of the gas’s ability to enter the small-size pore throat [13,14]. For medium and high permeability reservoirs, the main mechanism of gas flooding is to expand the swept volume, and maintain and restore reservoir pressure. Especially for the high dip angle reservoirs mentioned above, utilizing only water flooding for development results in a low sweep efficiency in the upper portion of the reservoir, which can quickly lead to low production and degassing of oil wells at the top, and the problem of safe treatment for excess produced gas. Gas injection at the high position is used to develop the remaining oil that cannot be swept by water drive. Generally, with the increase of inclination Angle, the higher the gas saturation at the high position is, the better the gas injection effect is. The simulated gas injection at the high position is 8.69% higher than that at the bottom position [15,16]. Therefore, the associated gas reinjection will be a more suitable approach to enhance the sweep efficiency of such reservoirs. However, gas injection in high-dip reservoirs must consider the appropriate integration with previously implemented water flooding, as well as achieving high recovery with limited gas injection volume. Currently, there is still a lack of comprehensive understanding regarding the mechanisms of gas injection in high-dip reservoirs with medium-high permeability, which consequently inhibits the ability to provide effective guidance for on-site implementation and may increase operational risks. Particularly, the influence of gas injection timing and gas injection mode on the development effect of high-dip reservoirs, as well as the related production mechanism are still under discussion.

Currently, in the study of gas injection in high dip reservoirs, one mechanism is the top stable gas injection gravity drive. The mechanism is mainly divided into three aspects.

(1)

Gravity differentiation. This development method adopts small flow development in the injection production process, and gives full play to the role of oil and gas Density contrast under the condition of low-speed development, making gravity the main driving force in the displacement process [17]. Under this development condition, the dispersed residual oil between wells is reaggregated to form a residual oil enrichment zone and continuously pushed downwards to the vicinity of the production well under gas drive conditions.

(2)

Reduce interfacial tension. In the process of top gas injection drive, when the gas injection pressure is greater than the minimum gas mixing pressure, gas and crude oil can be mixed. Under this condition, the gas dissolves in crude oil and the crude oil viscosity decreases and expands, reducing flow resistance and improving flow conditions.

(3)

Change the direction of liquid flow. In water drive development with low injection and high recovery, the flow direction of crude oil is bottom-up. When using top gas injection for development, the direction of liquid flow changed. For the remaining oil that is difficult to reach by water drive, it can also have better displacement, especially in the unspoiled area caused by the difference in oil-water mobility ratio and density, top gas injection displacement can increase the volume sweep efficiency and achieve enhanced oil recovery.

At present, the research on the mechanism of gas flooding in high-dip reservoirs is mostly conducted by using a two-dimensional visual sand-filling model and three-dimensional quartz sand cementation model, which both qualitatively and semi-quantitatively evaluate gas flooding sweep characteristics under various reservoir dip angles and physical properties [18,19,20]. It has been demonstrated that gas injection can effectively enhance the sweep efficiency of such reservoirs, which provides a crucial theoretical support for the practical application of gas injection in such reservoirs. However, the existing experimental methods have not taken into account the high-temperature and high-pressure characteristics of the actual reservoir. Especially for high dip angle reservoirs, the pressure difference between different parts of the reservoir is large, which will directly affect the pressure change in the areas under gas injection. Existing studies have mainly focused on assessing the impact of gas injection on reservoir development, with limited consideration given to the influence of varying water flooding conditions on gas injection [21,22]. This poses a challenge in terms of determining the practical implications of coordinated water and gas injection for field development. The study on gas injection mode is mostly achieved through numerical simulation, where many key parameters are directly influenced by human experience. Consequently, research results have a high degree of uncertainty. Moreover, there is a lack of physical model studies on injection modes, which will further unfavorably affect gas injection.

In this paper, two sets of physical simulation devices for studying the gas injection mechanism are established based on the actual reservoir, utilizing the similarity criterion that can reflect the gravity effect of high dip reservoirs. Firstly, a high temperature and high-pressure physical model device with variable dip angle is employed to quantitatively analyze the dynamic performance in different regions of the reservoir under various gas injection timing and injection types. Another is a two-dimensional visual physical simulation device with an adjustable dip angle, which has been developed to assess the impact of water and gas injection synergistic effects on reservoir development under various gas injection modes through the high-speed camera. Meanwhile, the imaging system, based on advanced image processing technology, enables quantitative analysis of the influence of gas injection on the reservoir’s sweep coefficient.

2. Experiment

2.1. Materials

Referring to the components of crude oil and associated gas in the actual reservoir, the ground-degassed crude oil is added to the container and vacuum treated in the laboratory. The remixed natural gas, whose components are according to the subsurface, is further placed in the container, with its temperature and pressure increased to the formation conditions (62.1 °C 11.91 MPa), and the container is rotated at 360°/min for 72 h to ensure the full mixing of oil and gas. The components of the remixed oil-containing gas in the subsurface conditions are shown in

Table 1. The components of oil and gas used in experiments. (weight%).

Component	N2	CO2	C1	C2	C3	C4	C5	C6	C7	C8	C9	C10	C11	C11+	Total
Oil in surface	0	0	0	0.25	0.52	1.18	2.15	2.63	3.26	3.98	3.73	3.55	3.6	75.15	100
Mixed gas	4.163	0.228	59.2	13.6	12.5	7	2	0.76	0.16	0.02	0.02	0	0	0	100
Mixed oil	0.54	0.03	7.7	1.99	2.09	1.94	2.14	2.39	2.86	3.47	3.25	3.09	3.13	65.38	100

. The water used in the experiment is referred to the salinity and composition of the formation water in the actual reservoir, and the specific information is shown in

Table 2. The information on water used in experiments.

Parameter Source		Sample 1	Sample 2	Sample 3	Value Used in Experiments
Cation (mg/L)	Na+ + K+	1448.8	502.1	423.9	791.6
	Ca2+	8	2.004	10.52	6.8
	Mg2+	/	1.337	4.71	3
Anion (mg/L)	Cl−	88.6	27.65	283.6	133.3
	HCO3−	3529.4	1106	592.3	1742.6
	SO42−	32.7	154.8	82.31	89.9
	CO32−	72.3	/	/	72.3
PH value		8.35	9.11		8.7
Total salinity (mg/L)		3015.5	1741	1403	2053.2
Water type		NaHCO3	NaHCO3	NaHCO3	NaHCO3

.

2.2. Experimental Apparatus and Procedures

The reservoir in this study has the characteristics of a high dip angle (average value of 17°, locally up to 25°). Physical simulation at the laboratory scale is difficult to realize the significant influence of fluid gravity on reservoir seepage. In this study, two sets of physical simulation devices will be established based on similarity criteria. Two sets of devices are shown in Figure 1. Firstly, the dynamic performance changes of gas injection in the high dip angle reservoir under high-temperature and high-pressure conditions will be studied. Subsequently, the effects of gas injection on the sweep efficiency in the high dip angle reservoir will be analyzed under visualization conditions.

2.2.1. Physical Model and Process of Gas Injection under High-Temperature and High-Pressure Conditions

The physical model encompasses three major systems of injection, monitoring, and production, with the key equipment being a long variable inclination sand-filled pipe of high temperature and high-pressure resistance. The pipe facilitates the differentiation of oil, gas, and water phases, which enables convenient observation of the migration characteristics of water and gas. In this study, the main advantages lie in the adjustable dip angle and the ability for multi-point pressure measurement, which enables real-time feedback of pressure monitoring data. Moreover, the model exhibits a maximum pressure and temperature resistance of 30 MPa and 150 °C respectively, fully meeting the actual conditions of the reservoir to be studied. The schematic diagram and parameters of the pipe are shown in Figure 2 and

Table 3. The key parameters of the sand filling pipe.

Parameter	Length, mm	Diameter, mm	Cross-Section Area, cm2	Volume, mL
Value	800	100	79	6283
Parameter	Number of Measuring Points	Dip Angle, °	Maximum Pressure Resistance, MPa	Maximum Temperature Resistance, °C
Value	33	0–90	30	150

.

Due to significant differences between the conditions of physical experiments and actual reservoirs, the utilization of similarity criteria is necessary to ensure that the conditions and results of experiments can most accurately reflect the actual reservoirs. This is vital for the advancement and development of reservoir engineering research. The reservoir to be studied has the characteristics of high dip angle. Therefore, the similarity criterion needs to reflect the influence of fluid gravity on the sweep performance of water and gas injection. The criteria here mainly include geometric similarity, physical similarity and mechanical similarity, among which the last one is the core of the criteria in this study. Here, the introduction of thickness factor β and gravity factor γ enhances the model’s representation of the influence of dip angle and corresponding gravity factors, accurately simulating the gravity-dominated displacement process in the reservoir. The detailed information is shown in

Table 4. The similarity criteria of high dip angle reservoir.

Similarity Criteria	Similarity Criterion Number	Physical Meaning
Geometric similarity	η1 = LR/Lm	Model and actual dimensions
	η2 = β hR/hm = LR/Lm	Thickness ratio
	η3 = θR/θm = 1	Dip angle ratio
Physical similarity	η4 = γ$\frac{K_{wro}{h}_m{\rho }_{o}g{h}_m}{q_w{\mu }_w}$	Flow design of injection
	η5 = γ$\frac{K_{gro}{h}_m{\rho }_{o}g{h}_m}{q_g{\mu }_g}$
	η6 = $\frac{\mathrm{Q}}{\mathrm{t}}$	Production time design
Mechanical similarity	η7 = $\frac{\left({\rho }_o-{\rho }_g\right)g{h}_m\sin {\mathsf{\theta }}_{\mathrm{m}}K}{{\mu }_o{v}_{og}{L}_m}$	Gravity number of gas flooding
	η8 = $\frac{\left({\rho }_w-{\rho }_o\right)g{h}_m\sin {\mathsf{\theta }}_{\mathrm{m}}K}{{\mu }_o{v}_{ow}{L}_m}$	Gravity number of water flooding

L_R: Length of the reservoir, m; L_m: Length of the model, m; h_R: Thickness of the reservoir, m; h_m: Thickness of the model, m; θ_R: Dip angle of the reservoir, °; θ_m: Dip angle of the model, °; K_wro: Water phase permeability under residual oil condition, mD; K_gro: Gas phase permeability under residual oil condition, mD; ρ_o: Oil phase density, kg/m³; ρ_w: Water phase density, kg/m³; ρ_g: Gas phase density, kg/m³; q_w: Water injection rate of model, m³/s; q_g: Gas injection rate of model, m³/s; Q: Injection volume, m³; t: Production time, s; v_og: Migration velocity of oil-gas interface, m/s; v_ow: Migration velocity of oil-gas interface, m/s; μ_o: Oil phase viscosity, mPa·S; μ_w: Water phase viscosity, mPa·S; μ_g: Gas phase viscosity, mPa·S; K: Permeability, mD.

. The specific parameters are compared in

Table 5. Comparison of parameters.

Parameter	Reservoir	Model	Scale
Length/m	2400	0.8	3000
Thickness/m	155	0.1	1550
Dip angle/°	17	17	1
Porpoty%	23	23	1
Permeability/10−3 μm2	1500	1500
Temperature/°C	62.1	62.1
Pressure/MPa	11.91	11.91
Oil phase viscosity/mpa·s	10.5	10.5	1
Water phase viscosity/mpa·s	1	1
Oil phase density/g·cm−3	0.8774	0.8774
Water phase density/g·cm−3	1	1
Water injection rate	188.892 m3/d	1.71 mL/min	7.6 × 104
Gas injection rate	500 m3/d	1.71 mL/min	2 × 105
Production rate	124.815 m3/d	4.53 mL/min	1.9 × 104

.

Using the high-temperature and high-pressure physical model, the development effect of a high dip angle reservoir is analyzed under varying conditions of gas injection timing and injection type. Moreover, six groups of displacement experiments were designed, the process of which is shown as follows.

Firstly, based on similarity criteria, the model assembly is conducted, primarily including sand filling, gas injection leakage test, and compaction. Subsequently, fluid saturation is achieved by means of vacuum extraction, self-priming water saturation, oil saturation, heating, and fixing the inclination angle of the pipe at 17°. Lastly, displacement experiments are conducted, sequentially involving depletion development, water injection on the bottom, gas injection at top, and water-gas development until the water cut of over 98%. In

Table 6. The main parameters of the physical simulation under high-Temperature and high-Pressure.

Experiment No.	Water Injection Timing	Gas Injection Timing	Sand Volume Filled	Permeability	Porosity	Gas Type
	%	%	cm3	mD	%
A1	40	40	6256.5	1483.76	22.69	N2
A2	60	50	6223.1	1521.45	23.45	N2
A3	80	70	6245.7	1501.99	23.03	N2
A4	40	40	6236.8	1514.38	23.14	Natural gas
A5	60	50	6247.2	1497.23	22.78	Natural gas
A6	80	70	6218.4	1534.54	23.61	Natural gas

, the injection timing refers to the pressure level of the pipe.

2.2.2. Physical Model and Process Gas Injection under Visualization Condition

The core equipment of visualization simulation is visualization devices. The device is a transparent sand-filled model, and a light source can be set on the bottom surface, and a camera can be set on the top to observe the law of water and gas migration. The seepage law of a high dip oil reservoir is visualized.

The components of visualized physics simulation are fundamentally consistent with those of high-temperature and high-pressure physical simulation. The key difference lies in the inability of the former to achieve high-pressure conditions that match the actual reservoir, while still providing comprehensive visualization analysis using high-definition cameras. In order to facilitate the observation of the characteristics of water flooding, 0.1% methylene blue was added to the injected water, and the fillers in the model were glass microbeads with a particle size of 0.03–0.2 mm. The key parameters of the visual physical device are shown in

Table 7. The key parameters of the visual physical device.

Parameter	Length, mm	Width, mm	Thickness, mm	Volume, mL
Value	400	200	5	400
Parameter	Number of Measuring Points	Dip Angle, °	Maximum Pressure Resistance, MPa	Maximum Temperature Resistance, °C
Value	9	0–90	5	90

.

Using the visual physical simulation device, the sweep characteristics of water injection and gas injection in high dip reservoirs are analyzed under various injection conditions. Moreover, three groups of displacement experiments were designed shown in

Table 8. The main parameters of the visual physical simulation.

Experiment No.	Gas Injection Timing	Porosity	Permeability	Initial Oil Saturation	Irreducible Water Saturation
	%	%	mD	%	%
B1	100	20.5	1425	83	17
B2	75	22	1530	81.2	18.8
B3	50	23.1	1511	82	18
Average		21.87	1488.67	82.07	17.93

, the process of which is shown as follows.

The model assembly, saturation of fluid, and inclination angle setting are essentially the same as the high-temperature and high-pressure experiments, while there are some differences in the displacement experiment. Due to the inability of the visualization model to withstand the high pressure consistent with the actual reservoir, this experimental section does not include depletion development. The displacement includes water injection at the bottom, gas injection at the top and water-gas development until the water cut of over 98%.

3. Results and Discussion

3.1. Displacement Performance and Recovery Factor Analysis

The impact of gas injection timing on development dynamics is analyzed under various water flooding conditions using the high-temperature, high-pressure physical simulation device. In this study, the natural gas injection experiment is taken as an example for analysis shown in Figure 3 and Figure 4. After a period of depletion development, the physical model initiates water injection at the bottom followed by gas injection at the top. In this process, the characteristics of pressure level, oil production, water cut, gas-oil ratio and recovery factor are included in this physical simulation.

In the case of early energy supplementation, i.e., experimental group A6, the physical simulation experienced depletion, causing the pressure level to decrease to 80%. The bottom water injection was then initiated, and when the pressure continued to decrease to 70%, the top gas injection was commenced until production ceased. The amount of injection is described here using PV, where PV refers to the ratio of the volume of injected water to the volume of underground pores. It can be observed that a gradual increase in the water cut of the well in the middle occurs, shortly after the onset of gas injection at the top, specifically when the injected fluid reaches 0.25 PV. As the gas flooding front from the top progressively reaches the production end upon fluid injection reaching 1.0 PV, the oil wall from the upper middle part is also pushed to the production end, leading to a rapid decrease in water content and a rapid increase in oil production. With the progression of water and gas injection, the water content increases again and the gas-oil ratio gradually rises. Eventually, when no more oil is produced, the final recovery degree reaches 64.12%.

For the scenario of mid-term energy supplementation, i.e., experimental group A5, the bottom water injection timing is at a pressure level of 40% decrease, and the top gas injection timing is at a continued pressure decrease of 50%. In this case, the initiation timing of top injection and the timing of water breakthrough at the production end are nearly simultaneous, and the water cut rise rate is faster than that of group A6. When the gas flooding front reaches the production end, the upper-middle oil well still causes a rapid decrease in water cut, however, to a lesser extent than A6. The final recovery factor is 59.31%.

In the case of late-stage energy supplementation, i.e., experimental group A4, water injection on the bottom is initiated when the pressure level to 40%, while simultaneously performing gas injection on the top. Under this condition, the gas flooding front reaches the production end prior to the water, and the water cut no longer exhibits a decline. Moreover, the production end quickly reaches its limit, with a final recovery factor of 54.53%.

Comparing the three experiments, it is observed that early energy supplementation results in a higher final recovery factor. In addition, injecting gas at the top yields better displacement efficiency for the middle and upper portion, with more pronounced oil wall effects and a slower water cut increase rate. The fluid injection only once the pressure level is lower than 60% of the original formation pressure could greatly reduce the efficiency of displacement. Future studies should focus on effectively controlling gas flooding and preventing channeling.

3.2. Contrast between Natural Gas and N2 Injection

Based on the high-temperature and high-pressure physical model, the effects of gas injection types, namely nitrogen gas and natural gas, on the gas flooding performance are investigated. It can be seen from Figure 5 that the gas breakthrough time of the natural gas injection scheme is later than that of the nitrogen injection, and the gas-free oil recovery period is longer. For the water cut, the oil wall effect under the natural gas injection scheme is better than that of the nitrogen, and the water cut curve decreases more obviously. In terms of the pressure at the end of the experiment shown in

Table 9. Production performance under various conditions at the end of the experiment.

Gas Injection Timing	Production Point Pressure at the End of the Experiment, MPa		Oil Recovery at the End of the Experiment, %
	Nitrogen Injection	Natural Gas Injection	Nitrogen Injection	Natural Gas Injection
40%	3.77	3.69	51.40	54.53
50%	6.63	6.59	58.02	59.31
70%	8.9	8.45	60.67	64.12

, the nitrogen flooding scheme yields better results than that of natural gas. Moreover, for the ultimate recovery factor, injecting natural gas outperforms injecting nitrogen gas.

The reasons behind the aforementioned phenomena can mainly be attributed to the following factors. Compared with natural gas, nitrogen gas has a lower density and higher specific volume under the reservoir conditions (Figure 6), leading to a more favorable effect on reservoir energy recovery and a greater swept volume. On the other hand, Natural gas, being highly soluble in crude oil, reduces the viscosity of crude oil and improves its fluidity, while also exhibiting a lower interfacial tension with crude oil, resulting in increased displacement efficiency.

Therefore, under the pressure and temperature conditions simulated in this experiment, it is found that pressure recovery with nitrogen injection has a limited impact on the improvement of the ultimate oil recovery, while natural gas injection shows superior advantages in enhancing the oil displacement efficiency, along with its ability to provide certain pressure maintenance effects. Thus, it can be concluded that natural gas injection is more favorable than nitrogen in terms of improving the ultimate oil recovery.

3.3. Visual Sweep Performance Analysis

Based on a visualization physical simulation apparatus, the study on sweep performance of water and gas flooding under different injection timing is conducted, shown in Figure 7. Due to the inability of the simulation equipment to withstand high pressure in an oil reservoir, the experiment is initiated with direct water injection followed by top gas injection. Throughout this process, the quantification of sweep characteristics of water and gas flooding is achieved through the utilization of image processing techniques.

For the experimental group B1, the physical modeling device simultaneously initiates bottom water injection and top gas injection. It can be observed that during the process of water and gas injection, the oil-water interface in the lower portion and the oil-gas interface in the upper portion are both in a steady state, with no apparent fingering phenomenon. During flooding, water injection highlights the effects of gravity, while gas drive demonstrates the influence of buoyancy.

In regards to the experimental group B2, the device initiates bottom water injection. Once the model pressure level decreases to 75%, top air injection commences. It is shown that the water-gas injection interface is relatively stable during the initial period. However, as displacement proceeds, the stability of the oil-water and oil-gas interfaces begins to deteriorate. By the end of the displacement, a smaller finger phenomenon has formed.

For the case of experimental group B3, the bottom of the instrument model is injected with water and when the model pressure dropped to 50%, gas is injected from the top. It can be found that clear-fingering phenomena occur at both the oil-water interface and oil-gas interface during the initial injection stage, which becomes increasingly pronounced as the displacement progresses, ultimately resulting in the formation of water and gas breakthrough channels.

Comparing the results of the three experimental groups, the early gas injection group shows the highest overall sweep efficiency and recovery factor, with values of 88.25% and 72.8%, respectively. The mid-term gas injection group has slightly lower values of 85.5% and 64.6%, respectively. The late-term group shows the lowest values of only 82.3% and 59.6%, respectively. Furthermore, in terms of the velocity of interface migration at the oil-water and oil-gas, it can be observed from Figure 8. that during the late-stage injection, the maximum velocity of interface migration is highest. This suggests that, compared to early-stage injection, it is more prone to the formation of fingering and channeling.

4. Conclusions

Two types of physical models that simulate gas and water drive for the high dip angle reservoir are constructed based on similarity criteria. A physical simulation apparatus is developed under high-temperature and high-pressure circumstances to explore the changes in dynamic indicators during the development of high-angle oil reservoirs. Under varied injection timing conditions, the effect of water and gas injection on oil recovery has been investigated. A visualization physical simulation apparatus has been created with the goal of examining the sweep performance of gas and water flooding in order to better understand the development features of high-dip angle reservoirs.

The development features of gas injection under various water injection conditions are examined using a high-temperature and high-pressure physical simulation equipment. In the experimental group of the same gas type, it can be seen that the earlier the formation energy is added, the better the development effect will be. According to the analysis of the experimental group A4–A6, the final recovery rate will be increased by 9.59% by injecting supplementary energy in advance. It is observed that early energy supplementation results in a slower rise in water cut, while gas injection leads to a greater reduction in water cut and ultimately leads to higher oil recovery. In addition, compared to other scenarios, the pressure level at the production end is considerably higher.

A visual physical simulation device is used to analyze the sweep performance at various gas injection timings. Compared with the stages of a, c and e, it can be seen that in the similar injection stage, the earlier the injection time, the better the injection fluid sweep effect. Early energy supplementation results in more uniform movement of the oil-water and oil-gas interfaces, which ultimately results in improved sweep efficiency. On the other hand, late-stage energy recovery causes phenomena such as water and gas channeling, which eventually cause the effect of sweep to rapidly degrade.

Pressure must be supplied early to achieve high sweep efficiency and recovery factor in order to develop high dip angle oil reservoirs effectively. Natural gas injection has been shown to be more efficient than nitrogen injection for this specific reservoir under the given pressure and temperature conditions in this study, owing to the benefits of natural gas in boosting oil mobility and its low carbon emissions.