Gas Injection Gravity Miscible Displacement Development of Fractured-Vuggy Volatile Oil Reservoir in the Fuman Area of the Tarim Basin

Abstract

This study investigates gas injection gravity miscible flooding to enhance oil recovery in fractured-vuggy volatile oil reservoirs of the Fuman area, Tarim Basin. The Fuman 210 reservoir, containing light oil with high maturity, large column heights, and strong fracture control, provides favorable conditions for gravity-driven flooding. Laboratory tests show that natural gas and CO₂ achieve miscibility, while N₂ reaches near-miscibility. Mixed gas injection, especially at a natural gas to nitrogen ratio of 1:4, effectively lowers minimum miscibility pressure and enhances displacement efficiency. Full-diameter core experiments confirm that miscibility improves oil washing and expands the sweep volume. Based on these results, a stepped three-dimensional well network was designed, integrating shallow injection with deep production. Optimal parameters were determined: injection rates of 50,000–100,000 m³/day per well and stage-specific injection–production ratios (1.2–1.5 early, 1.0–1.2 middle, 0.8–1.0 late). Field pilots validated the method, maintaining stable production for seven years and achieving a recovery factor of 30.03%. By contrast, conventional development relies on depletion and limited water flooding, and dry gas injection yields only 12.6%. Thus, the proposed approach improves recovery by 17.4 percentage points. The novelty of this work lies in establishing the feasibility of mixed nitrogen–natural gas miscible flooding for ultra-deep fault-controlled carbonate reservoirs and introducing an innovative stepped well network model. These findings provide new technical guidance for large-scale application in similar reservoirs.

1. Introduction

The Fuman Oilfield in the Tarim Basin, as a typical fault-controlled fractured-vuggy carbonate reservoir, features high-quality reservoirs distributed in vertical, slab-like formations [1]. In the test area, the oil column height ranges from 300 to 600 m [2]. Gas injection can fully leverage the characteristics of the reservoir, including its substantial vertical oil column height and the development of high-angle fractures, making it an ideal site for gas injection gravity drainage, where miscible displacement can be easily achieved [3,4,5,6].

As the main battlefield for increasing reserves and production in the Tarim Oilfield, the Fuman Oilfield primarily relies on the development of new wells, leading to a rapid increase in output with an average annual oil increase of 500,000 tons. The development results have been consistently positive [7]. However, the continued and stable production in the Fuman Oilfield also faces significant challenges [8]. The Fuman Oilfield primarily consists of fault-controlled fractured-vuggy carbonate reservoirs, classified as closed, under-saturated elastic-drive reservoirs. The previous development strategy mainly relied on natural energy depletion, supplemented by limited water flooding and dry gas injection, which led to rapid reservoir pressure decline, unstable production performance, and ultimately low recovery factors. These challenges highlight the urgent need to explore innovative and economically viable enhanced oil recovery (EOR) techniques suitable for ultra-deep carbonate reservoirs [9,10,11,12].

Extensive research, both domestically and internationally, has been conducted on methods for enhancing oil recovery (EOR) in fault-controlled fractured-vuggy reservoirs. These reservoirs differ from conventional clastic reservoirs, exhibiting extreme lateral heterogeneity and significant vertical oil column heights (400~1000 m) [13,14]. The reservoir characteristics resemble an “upright clastic reservoir,” making it well-suited for gas injection gravity drainage as an EOR method. Through research on reservoir development mechanisms and optimization of development methods, various gas injection media, including nitrogen, hydrocarbon gas, carbon dioxide, and mixed gases of hydrocarbons and nitrogen, were tested in fine-tube and displacement experiments [15,16]. These studies confirmed that both volatile oil and black oil in the major development test area can achieve miscibility at the current reservoir pressure. Full-diameter core displacement experiments further revealed the mechanisms of gravity miscible displacement and the distribution characteristics of residual oil [17,18]. This study focuses on Well Fuman 210 in the Fuman Oilfield, investigating the mechanisms of EOR through gas injection gravity miscible displacement. The research explores various aspects, including gas injection media, injection methods, injection rates, and injection–production ratios. The findings aim to provide theoretical support and technical guidance for transitioning the development methods of ultra-deep fault-controlled carbonate reservoirs in the Fuman Oilfield to enhance oil recovery.

2. Regional Geological Overview

The Fuman Oilfield in the Tarim Basin is located in the Aksu region of the Xinjiang Uygur Autonomous Region, situated in the Gobi area along the northern edge of the Taklamakan Desert. The terrain within the area is flat, with an elevation ranging from approximately 940 to 975 m above sea level. The surface is covered by floodplains, Gobi, and desert areas, and the region experiences a temperate continental arid climate. The Fuman Oilfield is located in the central part of the Amangou Transition Zone within the northern depression. The Amangou Transition Zone is situated between the “Two Uplifts and Two Depressions,” with the Tarbei Uplift to the north, the Central Uplift to the south, the Awaqi Depression to the west, and the Manjiaer Depression to the east.

The Amangou Transition Zone, where the Fuman Oilfield is located, has long been situated in a structural low between two ancient uplifts. During the sedimentation period, the water body was relatively deep with continuous strata, and it was located far from the Tarbei and Central ancient uplifts, lacking surface karst conditions. Observations from core samples in the Fuman Oilfield show that most effective pores and vugs are closely related to fractures. The dissolution phenomena do not selectively affect particles or cementing materials and exhibit characteristics of post-diagenetic burial dissolution. Three-dimensional seismic reservoir predictions for the Fuman Oilfield indicate that the fractured-vuggy reservoirs are distributed in a strip-like pattern along strike-slip faults in the plane. These reservoirs are concentrated within 100 to 2000 m of the strike-slip faults, with a peak width ranging from 200 to 400 m, and the reservoir belt can extend for hundreds of kilometers along the faults. Vertically, the reservoirs exhibit a flower-like or slab-like structure along the fault fracture zones, with prominent cross-layer characteristics. Typically, these reservoirs are developed within the range of 400 to 800 m in the Yingshan Formation, but can extend to over 1000 m. In areas without faults, there is generally a lack of development of fractured-vuggy reservoirs [19].

The development of the reservoir is controlled by fault structures. The more fault planes there are and the more complex the structure, the more developed the reservoir becomes. Reservoirs are most well-developed at intersections of multiple fault sets, in segments where faults are obliquely stacked and pulled apart, and in regions where fault planes exhibit ribbon-like twisting. Additionally, the continuous carbonate brittle layers of the Middle to Lower Ordovician, extending for thousands of meters, effectively protect the fault block reservoirs from compaction effects, allowing high-quality reservoirs to still develop at depths exceeding 8000 m [20].

Well Fuman 210 is part of the Ordovician reservoirs in the Fuman Oilfield, with the main productive formations being the Ordovician Yingshan Formation and the Yingshan Group. The top of the reservoir is buried at depths ranging from 7385 to 7525 m, with the central part of the reservoir at a depth of 7570 m and an elevation of −6605 m. Drilling has confirmed that the oil column height exceeds 270 m. The lithology is primarily composed of dolomitic limestone, dolomitic particle limestone, and mud-dolomite particle limestone. The primary storage space in the reservoir consists of large fracture-vug systems, with well-developed reservoirs and extremely strong heterogeneity [21].

3. Reservoir Characteristics

3.1. Crude Oil Characteristics

The carbonate fractured-vuggy reservoirs in the Fuman Oilfield exhibit an overall characteristic of “west oil, east gas; high density, low viscosity” with an ordered distribution (Figure 1). Moving from the Tarbei Uplift area towards the Amangou Low Ridge, the crude oil density transitions from >1.0 g/cm³ to 0.76 g/cm³. This gradient results in a sequence of heavy oil, light oil, volatile oil, condensate gas, and dry gas distribution zones. The characteristics include increasing burial depth approaching the hydrocarbon generation center, decreasing crude oil density, increasing gas–oil ratio, and rising oil and gas maturity [22].The differences in oil and gas properties are related to several factors, including the multi-stage hydrocarbon generation of the Cambrian Yurtus Formation source rocks, the Caledonian to Hercynian activity of strike-slip faults, and the distribution of Cambrian salt seals. In the Fuman Oilfield, the lack of Cambrian salt seals to the east of the Cambrian platform margin has led to early-formed reservoirs being modified into condensate gas reservoirs by natural gas charged during the Himalayan Orogeny. Conversely, in the Cambrian lagoonal salt rock distribution area in the central and western parts, the reservoirs have been minimally affected by late-stage gas invasion and are predominantly characterized by Hercynian normal oil reservoirs and volatile oil reservoirs.

The Fuman 210 Well reservoir predominantly contains light crude oil, with an average crude oil density of 0.8135 g/cm³ and an original gas-to-oil ratio of 162 m³/m³, indicating a high level of oil and gas maturity. The Fuman 210 Well area exhibits characteristics of “light, low viscosity, low sulfur, and low content of asphaltenes and resins.” The surface crude oil density ranges from 0.8107 to 0.8162 g/cm³ (at 20 °C), with an average of 0.8135 g/cm³, classifying it as light crude oil. The dynamic viscosity (at 50 °C) ranges from 2.045 to 2.306 mPa·s, with an average of 2.176 mPa·s. The pour point ranges from −12.0 to −18.0 °C, with an average of −15.0 °C, indicating a relatively low pour point. The sulfur content ranges from 0.167% to 0.175%, with an average of 0.171%. The content of resins and asphaltenes ranges from 0.38% to 0.73%, with an average of 0.555%.

3.2. Reservoir Characteristics and Distribution

The Ordovician carbonate reservoirs in the Fuman Oilfield are carbonate fractured-vuggy reservoirs controlled by strike-slip faults [23]. In plain view, oil and gas are primarily distributed in a strip-like pattern along major deep-seated source faults or secondary faults associated with them. Typically, “major faults correspond to major reservoirs” and “minor faults correspond to minor reservoirs.” The main fault belts generally have oil column heights exceeding 400 m. There is no uniform oil–water interface across different fault belts or within different segments of the same fault belt.

The oil and gas in the Amangou Transition Zone primarily originate from the Lower Cambrian Yurtus Formation slope facies condensed source rocks in the lower part of the zone and the Cambrian to Middle-Lower Ordovician basin slope facies source rocks in the eastern Manjiaer Depression. Comprehensive studies of fluid inclusions and the geochemical characteristics of oil and gas indicate that the critical periods for oil and gas accumulation were during the late Hercynian and Himalayan epochs. The characteristics of oil and gas accumulation include “Cambrian hydrocarbon supply, multi-stage accumulation, fault-controlled reservoirs, and vertical migration and accumulation.” After the Silurian sedimentation during the Caledonian epoch, extensive oil generation occurred in the northern depression, with well-developed strike-slip faults. Due to relatively weak diagenesis, the connectivity of faults and reservoirs is good, allowing oil and gas to primarily migrate and accumulate towards the high parts of ancient uplifts. In the Upper Ordovician mudstone thinning and pinch-out zones, intense oxidation and degradation occurred, leading to the formation of heavy oil and asphaltene distribution areas. Early asphaltene residues were observed in core samples from multiple wells in the Fuman area. After the Permian sedimentation during the Hercynian epoch, increased geothermal gradients due to igneous activity and widespread activation of strike-slip faults led to the vertical migration and accumulation of a large amount of light oil along these faults. This resulted in extensive Ordovician reservoir formation in the Fuman area. Since the Himalayan Orogeny, the Manjiaer Depression has become a gas generation center due to its greater burial depth and higher geothermal gradient. In the region lacking Cambrian salt on the Cambrian platform margin, severe gas invasion occurred, transforming early-formed oil reservoirs into condensate gas reservoirs due to later gas charging. In contrast, in the central and western regions, where salt layers provide plastic seals, only localized late-stage point charges occurred along major strike-slip faults. This has ultimately resulted in the current distribution pattern of “west oil, east gas” [24].

In the Fuyuan 210H Well area, to which the Fuman 210 Well reservoir belongs, oil wells are distributed in both the high and low structural positions, with no unified oil–water interface. Currently, no formation water has been observed in any wells within the fault zones, indicating good overall oil and gas charging. The reservoir is primarily controlled by strike-slip faults and is classified as an unsaturated carbonate fractured-vuggy reservoir with a normal temperature/pressure system. The fractured-vuggy reservoirs are developed along the faults, and the oil column height is relatively large [25].

4. Materials and Methods

To evaluate the mechanisms of enhanced oil recovery through gas injection gravity miscible displacement, a series of laboratory experiments were conducted under controlled high-temperature and high-pressure (HTHP) conditions. All experiments were carried out in the Petroleum Engineering Laboratory of China University of Petroleum (East China).

4.1. Experimental Equipment and Calibration

Experiments were performed using a HTHP core flooding system (Temco Engineering, Pomona, CA, USA), consisting of a displacement pump, stainless-steel core holder, high-precision backpressure regulator, and real-time data acquisition system. The system allowed pressure measurements up to 120 MPa and temperatures up to 150 °C, covering the range of conditions encountered in the Fuman 210 reservoir. The gas injection system was equipped with high-purity gas cylinders of CO₂ (99.99%), N₂ (99.99%), and natural gas (95.6% CH₄, balance C₂–C₄).

Calibration of all sensors (pressure transducers and thermocouples) was conducted prior to each experiment using certified reference standards. The pressure gauges were calibrated with a deadweight tester (±0.05 MPa accuracy), and the thermocouples were calibrated against a standard mercury thermometer (±0.1 °C accuracy). The displacement pump volume accuracy was verified by repeated gravimetric calibration with distilled water.

4.2. Reservoir Condition Simulation

To replicate reservoir conditions, the experiments were conducted at a temperature of 120 ± 1 °C and an initial pressure of 67.2 MPa, corresponding to the actual formation conditions of the Fuman 210 well. The confining pressure applied to the full-diameter carbonate core samples was maintained at 75 MPa to ensure radial sealing and simulate reservoir overburden.

4.3. Core Samples

Full-diameter cores (50 mm × 300 mm) were extracted from the Fuman 210 well, primarily composed of dolomitic limestone. All cores were cleaned using Soxhlet extraction with toluene and methanol for 72 h, dried at 105 °C, and vacuum-saturated with formation brine (salinity 58,000 mg/L NaCl equivalent) before flooding tests. Core porosity and permeability were measured by helium porosimetry and nitrogen gas permeametry, respectively, prior to experiments.

4.4. Experimental Design

Three sets of experiments were conducted:

Minimum Miscibility Pressure (MMP) Tests: Conducted using the rising-bubble apparatus (RBA) to determine miscibility pressures of CO₂, N₂, and natural gas. Each test was repeated three times to ensure reproducibility, and the average value was reported.

PVT Expansion Tests: Conducted in a PVT cell under reservoir temperature to measure crude oil swelling and viscosity reduction when contacted with different injection gases. Each condition was tested in duplicate.

Displacement Experiments: Gravity drainage experiments were performed under HTHP conditions with injection gases (CO₂, N₂, natural gas, and mixed gases at ratios of 1:1, 1:2, 1:3, 1:4). Each displacement test was repeated two times, and average recovery factors were reported. Effluent fluids were collected and analyzed for oil-gas ratios and composition using a gas chromatograph (Agilent 7890B).

4.5. Data Acquisition and Processing

All experimental data (pressure, temperature, flow rates, recovery factors) were logged automatically at 1 Hz frequency and processed using MATLAB R2023a. Recovery efficiencies were calculated as the ratio of displaced oil volume to initial oil in place within the core. Standard deviations were included in the results to reflect experimental repeatability.

5. Mechanisms of Enhanced Oil Recovery Through Gas Injection Gravity Miscible Displacement

Gas injection is currently the most effective method for enhancing oil recovery. In the United States, in Canada, where natural gas resources are abundant, hydrocarbon gas injection is predominantly employed. In this study, experiments were conducted on the Fuman 210 reservoir to investigate the effectiveness of CO₂, nitrogen (N₂), and hydrocarbon gases as injection media. Results indicate that a nitrogen–natural gas mixture at a 1:4 ratio reduced the minimum miscibility pressure to 66.7 MPa, slightly below the reservoir pressure of 67.2 MPa, thereby achieving effective miscible displacement under actual reservoir conditions for the first time. This approach not only addresses the poor miscibility and low efficiency of pure nitrogen but also avoids the high cost and limited supply of natural gas, as well as the corrosiveness and supply challenges of CO₂. The mixture markedly enhanced displacement efficiency and sweep volume, ultimately improving recovery, and thus represents the most technically feasible and economically viable injection scheme [26].

5.1. Evaluation of Injection Gases

Laboratory experiments on minimum miscibility pressure (MMP) indicate that natural gas and carbon dioxide (CO₂) can achieve miscibility in the Fuman 210 Well area, while nitrogen (N2) can achieve near-miscibility. The current formation pressure in the Fuman 210 Well area is 67.2 MPa. The minimum miscibility pressures are 56.4 MPa for natural gas, 46.2 MPa for CO₂, and 70.3 MPa for nitrogen (Figure 2). An uncertainty analysis of the experimental data was conducted (Figure 3).

The characteristics of fault-controlled vertical plate-like reservoirs differ from those of clastic rock layered reservoirs. The oil columns are generally greater than 300 m in height, with well-developed high-angle fractures. Gas injection primarily relies on gravity drainage, and miscibility improves the efficiency of oil recovery (Figure 4).

Figure 2 Common Injection Gas Medium Capillary Tube Experiments for Well Fuyuan 210H, conducted under reservoir temperature (120 °C) and pressure (67.2 MPa) conditions.

Experiments on the minimum miscibility pressure (MMP) of different ratios of mixed gases with crude oil show that natural gas has a stronger miscibility capability than nitrogen. As shown in Figure 5, the MMP of the mixed gas with crude oil decreases as the proportion of natural gas increases. When the ratio of natural gas to nitrogen is 1:4, the MMP is reduced to 66.7 MPa, which is slightly below the reservoir pressure (67.2 MPa), thereby enabling miscibility under actual formation conditions. This confirms the observed downward trend of MMP with increasing natural gas content in the mixture, supporting the key conclusion of this study. When the mixed gas (natural gas: nitrogen = 1:4) has a miscibility pressure of 66.7 MPa, which is lower than the current formation pressure of 67 MPa, miscibility conditions can be achieved.

The miscibility of hydrocarbon gas with crude oil is stronger than that of nitrogen. The expansion effect of the mixed gas on crude oil shows an increasing trend. For a mixed ratio of natural gas to nitrogen (1:4), the expansion coefficient of crude oil under formation temperature and pressure (67 MPa) is 13%, while under original formation temperature and pressure (77.67 MPa), the expansion coefficient is 18%.

By conducting full-diameter core displacement experiments for fractured-vuggy reservoirs under high temperature and high pressure, the enhanced oil recovery effects of different injection gases using gravity drainage were clarified. The experimental design includes nitrogen (N₂), 0.2 HCPV natural gas plug + N₂, and mixed gases (natural gas: N₂ = 1:1, 1:2, 1:3, 1:4).

Factors affecting oil recovery through gas injection include displacement method (gravity drainage, injector and producer well locations), fluid viscosity ratio, compatibility of injected gas phases, flow heterogeneity, and wettability. The main controlling factors for residual oil distribution are: (1) Fracture-vug location: Low-lying areas that are difficult for the injected gas to reach. (2) Wettability: Surfaces of oil-wet particles and pore surfaces. (3) Heterogeneity: Localized flow resistance due to filling effects in certain particle regions [27].

Mixed gas mediums are superior to pure nitrogen gas for enhanced oil recovery, leveraging the dual effects of nitrogen for energy supplementation and natural gas for increased displacement efficiency [28]. Two injection methods were compared: (1) injecting 0.2 HCPV of natural gas as a pre-flush followed by 0.8 HCPV of nitrogen; (2) mixed injection of natural gas and nitrogen at a ratio of 1:4. The first method benefits from the initial phase where natural gas improves crude oil properties and solubility extraction through miscibility (initially high). The second method utilizes nitrogen for energy supplementation and natural gas to increase displacement efficiency (slightly higher towards the end). Among various natural gas and nitrogen mixing ratios, the natural gas: nitrogen ratio of 1:4 showed the greatest increase in recovery rate (Figure 6). An uncertainty analysis of the experimental data was conducted (Figure 7).

Figure 8 Visualization of gas migration in porous media. During the area-driven gas overflow stage, the distribution of gas and liquid volumes becomes uneven, with gas occupying 55.2% of the total volume and liquid occupying 44.8%. At this stage, the injected gas diffuses laterally, forming a gas cap, and its downward migration rate gradually increases. Once the gas cap is established, the injected gas transitions into a vertical oil displacement phase, maximizing the affected volume. When the flow regime shifts from area-driven to gravity-driven, the gas–liquid interface stabilizes and moves downward, leading to a further 40.4% expansion of the affected volume. Laboratory results indicate that gravity drainage can increase the affected volume by an additional 40.4% compared to area-based displacement methods. This process not only optimizes gas distribution but also enhances the effective control and recovery efficiency of fluids within porous media (Figure 8).

Miscible displacement can efficiently displace crude oil in fractures and vugs and move remaining oil from higher to lower positions. During actual field gas injection production, it is recommended to use an infill well pattern to “connect” high-position attic oil and thereby expand the affected volume [29].

Compared to water flooding, gas flooding can further enhance oil recovery. When comparing different injection methods, low injection with high production in the early stages yields a higher recovery rate than high injection with low production. However, in the mid to late stages, gas breakthrough occurs more rapidly. In actual field gas injection production, it is recommended to use a high injection and low production method (Figure 9).

Laboratory experiments indicate that high-angle fractures have a positive effect on gas injection gravity drainage technology. Initially, the injected gas rapidly channels through the fractures, but due to gas segregation, a “self-balancing” stable gas–liquid interface gradually forms.

In actual field gas injection production, it is recommended to use a large PV long-term continuous gas injection method. This approach facilitates the diffusion of injection well pressure, stabilizes the gas–liquid interface, and further expands the swept volume.

5.2. Optimal Selection of Gas Injection Medium

Based on the analysis of miscible displacement mechanisms, displacement efficiency, experimental significance, and recovery degree, nitrogen mixed with natural gas is selected as the injection medium for the proposed plan (

Table 1. Comparison Table of Different Injection Gases.

Injection Medium	Advantageous Conditions	Limiting Factors
Carbon Dioxide (Restricted gas supply)	① Can achieve miscibility with crude oil, enhancing oil recovery efficiency. ② Easily dissolves in crude oil, reducing its viscosity and flow resistance.	Restricted gas supply (remote sources, insufficient volume), high surface investment, poor gravity segregation, high gas consumption, and pipeline corrosion are issues.
Natural Gas (Non-economic)	① It can form a miscible phase with crude oil, improving oil displacement efficiency; ② Rich practical experience in Yaha and Donghe can be referenced.	1. High surface investment required, insufficient gas supply, with significant economic value of natural gas; 2. Neighboring Shunbei area has already conducted natural gas injection experiments, with limited experimental scope.
Nitrogen (Non-miscible)	① In near-miscible state, the small volume coefficient is advantageous for energy supplementation; ② The on-site preparation of nitrogen and injection technology is well-develop; ③ Inert gas, with low operational risk.	The cost of dispersed gas injection is high, and there are corrosion issues with the tubing.
Nitrogen-Mixed Natural Gas	① Can be miscible with crude oil, improving oil recovery efficiency; ② Requires less natural gas, with objective economic benefits; ③ Significant for major development trials, exploring the first nationwide application of nitrogen miscible gravity displacement effects.	The surface pipeline network is complex.

Note: The term “non-miscible” refers specifically to pure nitrogen, which is unable to attain first-contact miscibility (FCM) under the prevailing reservoir pressure in this block (MMP_N₂ ≈ 70.3 MPa > 67.2 MPa). However, when nitrogen is blended with natural gas at a 1:4 ratio, the mixture reaches critical enrichment. If the reservoir pressure exceeds the minimum miscibility pressure (MMP) of the blended gas (≈66.7 MPa), the system is capable of achieving dynamic miscibility through multi-contact miscibility (MCM) mechanisms.

).

5.3. Gas Injection Method

Based on the completion characteristics of fractured-vuggy carbonate reservoirs, the gas injection gravity drainage combined with a stepped three-dimensional well pattern is adopted. Phase one: continuous gas injection. Phase two: According to the gas–liquid interface position, adjust the injection–production relationship or deepen old wells to reconstruct the stepped three-dimensional well pattern (Figure 10) [30].

Based on indoor mechanisms and gravity drainage field practices, gravity segregation effects outweigh gas injection diffusion effects, and high injection-low production methods help delay gas breakthrough. A combination of vertical and horizontal wells in a stepped pattern is used to leverage the gravity segregation effect of the gas. Top gas injection forces the attic oil downward for gravity drainage (Figure 11).

5.4. Gas Injection Rate

Comparing different gas injection rates per well (30,000; 50,000; 100,000; 150,000 cubic meters per day), as the injection volume increases, some wells experience gas breakthrough, affecting the stability of the gas–liquid interface. To maintain stability of the gas–liquid interface, the gas injection rate per well should be controlled at 50,000 to 100,000 cubic meters per day.

5.5. Injection–Production Ratio

The design of the injection–production ratio primarily considers the formation of a pressure gradient in the vertical direction to ensure the stability of the gas–liquid interface. In the early stages of gas injection, the focus is on expanding the scale of the secondary gas cap, with an initial injection–production ratio controlled at 1.2 to 1.5. In the middle and later stages, the gas–liquid interface is determined, the oil column is tracked, and adjustments to the gas injection rate are made based on the evaluated gravity-driven oil production, with high gas-to-oil ratio wells being shut in. During the mid-stage, the injection–production ratio is controlled at 1.0 to 1.2, and in the later stage, it is controlled at 0.8 to 1 (Figure 12).

5.6. Impact of Gas Injection Gravity-Enhanced Miscible Displacement on Recovery Efficiency

Well 201 uses 6 wells: 2 for injection and 4 for production, with shallow injection and deep production. Mixed gas (natural gas + nitrogen) is used for development, with the injection wells supplying 20 × 10⁴ m³ of mixed gas per day (natural gas to nitrogen surface volume ratio of 1:4). The cumulative injection of mixed gas is 6.45 × 10⁸ m³, with a peak annual injection volume of 0.65 × 10⁸ m³. The annual oil production is 40,000 tons, maintaining stable production for 7 years. At the end of the evaluation period, the cumulative oil production is 70.87 × 10⁴ tons, with a recovery degree of 30.03% of the geological reserves, which is 17.4 percentage points higher than the conventional development scheme that mainly relied on natural depletion, limited water flooding, and dry gas injection (Figure 13).

6. Conclusions

The Fuman Oilfield in the Tarim Basin is part of the Ordovician reservoir, with its main productive formations being the Yijianfang Formation and the Yingshan Formation of the Ordovician. The central depth of the reservoir is 7570 m, and the primary storage space is dominated by a large-scale fractured-vug system with strong heterogeneity. This study confirms that natural gas and carbon dioxide can achieve miscibility with crude oil in the Fuman 210 Well, while nitrogen alone only reaches a near-miscible state. More importantly, when nitrogen is mixed with natural gas at a ratio of 1:4, the system can achieve miscibility under actual reservoir conditions, effectively reducing the minimum miscibility pressure and significantly improving oil displacement efficiency. This finding provides an innovative technical solution for ultra-deep fault-controlled reservoirs and offers a practical pathway for balancing technical feasibility with economic viability by reducing reliance on natural gas and CO₂.

A key insight is that the geometry of the fractured-vuggy reservoir, especially the presence of high-angle fractures, strongly favors gravity-driven miscible flooding. These structural characteristics enhance the sweep efficiency of injected gas and expand the recovery volume, demonstrating that reservoir architecture plays a decisive role in optimizing enhanced oil recovery (EOR) strategies. Moreover, the stepped three-dimensional well network proposed in this study highlights the importance of well pattern design in delaying gas breakthrough and maintaining production stability, providing valuable guidance for future field implementation.

In practical terms, the results suggest that nitrogen–natural gas mixed injection represents a technically robust and economically sustainable strategy for similar ultra-deep carbonate reservoirs, particularly in areas where natural gas supply is limited and CO₂ injection is constrained by cost and corrosion risks. Future research should focus on scaling up pilot tests to full-field applications, investigating the long-term geomechanical impacts of gas injection, and integrating real-time monitoring with reservoir simulation to refine control strategies. Such efforts will further validate the effectiveness of mixed gas gravity miscible flooding and extend its applicability to other complex carbonate reservoirs worldwide.