Comprehensive Study of Development Strategies for High-Pressure, Low-Permeability Reservoirs

Abstract

Currently, there is no well-established framework for studying development patterns in high-pressure, low-permeability reservoirs. The key factors influencing development effect typically include the reservoir properties, well pattern, well spacing, and the rate of oil production. Reservoir A is a representative of this type of reservoir. Starting from its physical properties, a study of the development mechanism was conducted using the tNavigator (22.1) software. A total of 168 sets of numerical experiments were conducted, and 3D maps were innovatively created to optimize the development mode. Building upon the preferred mode, an exploration was carried out for the applicability of gas flooding and the optimization of water flooding schemes for such reservoirs. All experimental results were reasonably validated through Reservoir A. Furthermore, due to the high original pressure in such reservoirs, the injection of displacement media was challenging. Considering economic benefits simultaneously, a study was conducted to explore the rational utilization of natural energy. The research proved that for a reservoir with a permeability of about 10 mD, the suitable development scheme was five-point well pattern, a well spacing of 350 m, water–gas alternating flooding, and an initial oil production rate of 2%. When the reservoir underwent 8 months of depleted development, corresponding to a reduction in the reservoir pressure coefficient to 1.09, the development efficiency was relatively favorable. Over a 15-year production period, the oil recovery reached 29.98%, the water cut was 10.31%, and the reservoir pressure was maintained at around 67.18%. The geology of the newly discovered reservoir is not specific in the early stage of oilfield construction, and this research can help to determine a suitable development scheme.

1. Introduction

In China, there are numerous low-permeability oil reservoirs, and their flow characteristics are mainly non-Darcy flow. Abnormally high-pressure low-permeability reservoirs, as a specific type of low-permeability reservoir, are mainly distributed in regions such as Xinjiang, Bohai Sea, South China Sea, and Sichuan [1,2,3,4]. These reservoirs typically share the following characteristics: deep deposition, high original reservoir pressure, strong heterogeneity, complex geological structures, and rock pore structures, making oil–water flow challenging. The production conditions for such reservoirs often include high initial production rate, difficulties in water injection, and a sharp decline in production as the reservoir pressure decreases. A rapid pressure decline rate often results in irreversible damage to rock properties, exhibiting strong pressure-sensitive characteristics. However, for the special reservoirs with such characteristics, the main development methods are still water flooding and gas flooding [5,6].

Water flooding, with its economic advantages, remains the primary development method for low-permeability reservoirs. During the process of reservoir exploitation, as pore pressure decreases, the effective pressure on the reservoir increases, causing rocks to undergo elastic–plastic deformation, leading to partial or complete irreversible changes in permeability and porosity [7,8,9,10,11,12]. For continuous water flooding, the injected water generally flows along the high permeability channel, and the displacement efficiency is low. Unstable water flooding can creat a pressure difference between the layers with different permeability, and more crude oil can be produced under the action of capillary force [13,14,15]. Advanced water injection can effectively reduce the detrimental effects caused by the pressure-sensitive characteristics of low-permeability reservoirs. For general low-permeability reservoirs, advanced water injection can be adopted. When the reservoir pressure coefficient is controlled between 1.05 and 1.2, the development effect of the reservoir is better [16,17].

Gas flooding, including CO₂ flooding and N₂ flooding, is also a crucial means to enhance oil recovery. With increasing injection pressure, CO₂ extracts more light components and achieves miscibility with crude oil, resulting in viscosity reduction, expansion, and ultimately increasing oil recovery [18,19]. N₂ typically has difficulty achieving miscibility under reservoir conditions. In sandstone reservoirs, injecting formation water before CO₂ injection primarily enhances permeability through dissolution [20,21]. Simultaneously implementing both pressure retention and water-alternating-gas (WAG) flooding is costly but can significantly increase oil recovery [22,23,24,25,26,27]. Pure CO₂ offers higher oil recovery and net present value compared to impure CO₂ [28,29,30,31].

Nowadays, a large numbers of efforts have been made on the application of water and gas flooding to reservoir development, but a definitive solution of how to formulate a complete development system that suits the actual reservoir has not yet appeared, especially for special types of reservoirs such as abnormally high-pressure and low-permeability reservoirs, which is an important factor that needs to be solved and improved.

In this study, the mechanism of influencing factors of reservoir development effect, the applicability of gas flooding, the optimization of water flooding scheme and the rational utilization of reservoir natural energy were studied. All the experimental results were obtained using the mechanism model and verified with Reservoir A, which ensured the rationality of the research. The results of this study can provide robust reference for the development of similar reservoirs, ensuring the establishment of rational development strategies.

2. Materials and Methods

2.1. Description of Reservoir A

Reservoir A is located in Xinjiang, China, and is a newly discovered oil-bearing area. Reservoir A is deposited at a depth of approximately 2842 m to 3427 m. Its sedimentary structure is characterized as follows: at the bottom, it exhibits planar bedding; in the middle, it displays channelized and interbedded bedding; and at the top, it shows parallel bedding. The reservoir rocks exhibit hydrophilic properties, and within the study area, the reservoir demonstrates characteristics of weak sensitivity to production rate, moderate sensitivity to salinity, strong sensitivity to pressure, and weak sensitivity to water. There is no edge water in the oil reservoir, and the distribution of oil and water within the reservoir is primarily controlled by lithology and structure.

Reservoir A primarily consists of mudstone and fine sandstone with a mud content of 8.9%. Lithic feldspar sandstone and feldspar lithic sandstone are the main rock types. The sandstone cement particles typically have diameters ranging from 0.04 mm to 0.16 mm, with a maximum size of 0.23 mm. The sorting coefficient is 1.14, indicating relatively poor sorting. The mean particle size is 0.073 mm. The rocks are mainly in linear and point-line contact, the cementation mode is porous cementation, and the cement is mainly carbonate rock. Its original reservoir pressure, reservoir pressure coefficient, average porosity, and average permeability are 41 MPa, 1.25, 18.2%, and 12.28 mD, respectively. It is classified as an abnormally high-pressure low-permeability reservoir. The average original oil saturation is approximately 50%. At reservoir temperature, the crude oil has a saturation pressure of 10.85 MPa, a volume factor of 1.436, a viscosity of 5.98 mPa·s, a density of 0.6325 g/cm³, a gas–oil ratio of 46.70 m³/t, a degassed density of 0.828 g/cm³, a wax of 24.69%, a resin of 12.81%, an asphaltene of 2.13%, and a freezing point ranging from 12 to 24.4 °C.

Several wells were used to test oil production in Reservoir A before it was put into development, among which the production conditions of A10 and A13 were generally representative. Reservoir A showed obvious production characteristics of a rapid decline in production rate and rapid increase in water cut (Figure 1 and Figure 2). How to prolong the stable production stage of such reservoirs and improve oil recovery is an urgent problem needing to be solved.

2.2. Mechanism Study of Abnormally High-Pressure Low-Permeability Reservoirs

A mechanistic model was established according to the actual geological parameters of Reservoir A, with a grid size of 10 m × 10 m × 10 m, a porosity of 18.2%, a permeability of 12.28 mD, an initial oil saturation of 50%, and an initial average reservoir pressure of 41 MPa. The relative permeability characteristics of oil–water and oil–gas were measured with experiments (Figure 3 and Figure 4).

A total of 168 groups of mechanistic models with various physical properties and production modes were established (

Table 1. Parameters of mechanistic model.

Parameter	Value
Permeability (mD)	1, 3, 5, 7, 10, 30, 50
Well pattern type	five-spot, inverted seven-spot, inverted nine-spot
Well spacing (m)	200, 300, 400, 500
Oil production rate (%)	2 (15a), 3 (10a)

).

Different reservoirs have different controls on the speed of oil or liquid production. The concept of oil production rate was applied to allocate the production of oil wells in the form of percentage, so as to compare the production status of oil reservoirs with different oil production speeds. The concept refers to the ratio of the annual oil production of a field to the geological reserves.

The orthogonal simulation experiments all employed an injection–production ratio of 1:1 for water flooding simulation. Evaluation criteria for different schemes included oil recovery, water cut, and reservoir pressure maintenance. These evaluations were used for scheme optimization.

2.3. A Study on the Gas Flooding and Optimization of Water Flooding Schemes

In order to conduct gas flooding development research and optimize the water flooding scheme, a comparison of the following schemes was carried out based on a five-spot well pattern with a well spacing of 350 m and an oil production rate of 2%:

• Continuous Water Injection (CWI);
• 30-Day Periodic Water Injection (PWI);
• Continuous CO₂ Injection (CCI);
• Continuous N₂ Injection (CNI);
• 30-Day Periodic CO₂ Injection (PCI);
• 30-Day Periodic N₂ Injection (PNI);
• 30-Day Water-CO₂ Alternating Injection (WACO₂);
• 30-Day Water-N₂ Alternating Injection (WAN₂).

Considering the high original reservoir pressure, the injection of CO₂ and N₂ may lead to the formation of a gas–oil miscibility, resulting in a miscible displacement process. To ensure that the reservoir pressure remains above the minimum miscibility pressure (MMP) during development, it is necessary to study the MMP, which is a crucial parameter that determines whether gas and oil can form a miscible mixture. The capillary tube experiment was carried out.

We conducted numerical simulation research for gas flooding using a single-factor control variable method, controlling the volume of injected gas to maintain a water-to-gas volume ratio of 1:1 under reservoir conditions. Under reservoir conditions, the volume ratio of water and gas in the water–gas alternating scheme was also maintained at 1:1. Gas volume can be converted using the gas state equation.

2.4. Application of Mechanism Research Conclusions

The distribution of physical properties in the mechanism model is very uniform. Its calculation results represent the development effect of homogeneous reservoirs in general. It needs to be confirmed whether the conclusions obtained from the mechanism study experiment can be directly applied to the actual reservoir.

2.5. Rational Use of Natural Energy

Due to the characteristic of exceptionally high initial reservoir pressure, injecting displacement media in the field presents significant challenges. Additionally, there is a substantial difference between the original reservoir pressure and the saturation pressure of the crude oil. From an economic perspective, it is worth exploring whether some degree of utilization of the original reservoir energy is feasible. This involved a period of depletion development, followed by water or gas injection for production.

3. Results and Discussion

3.1. Mechanistic Model Research Findings

Through 168 groups of mechanism model experiments, the production conditions of different well spacing, well pattern, oil production rate, and formation with different permeability were studied, and the optimal selection maps of development mode were drawn comprehensively (Figure 5, Figure 6 and Figure 7).

Based on the results (Figure 5, Figure 6 and Figure 7), it was advised not to use a high oil production rate for the development of low-permeability reservoirs. A higher oil production rate might lead to a sharp decrease in reservoir pressure around the oil wells. When the well spacing was large, the energy of injection end was limited by the reservoir permeability and conducted slowly. Even if the overall reservoir energy was at a high level, the distribution of energy was that it was high near the injection wells and low near the production wells, leading to delayed energy conduction, and the oil well productivity was less likely to recover.

The production-to-injection well ratios for the five-spot, inverted seven-spot, and inverted nine-spot well patterns were 1:1, 1:2, and 1:3, respectively. The production characteristics of the inverted seven-spot and inverted nine-spot well patterns were significantly affected by changes in well spacing, but the three well patterns showed little variation in production characteristics in the permeability range of 3 mD to 10 mD. When the well spacing was the same, the five-spot well pattern had the lowest well density, which also represented the maximum distance between injection and production wells (Figure 8, Figure 9 and Figure 10). This was why the five-spot well pattern had the lowest water cut.

Therefore, for low-permeability reservoirs, especially ultra-low-permeability reservoirs developed using the five-spot well pattern, it is suitable to use small well spacing and a low oil production rate.

From the simulation results, it could be observed that a permeability of 20 mD was a critical point for changes in oil–water production characteristics. When the permeability exceeded 20 mD, the pore diameter of the rock increased, the capillary force decreased, and the water phase fluidity increased. In a dense well pattern, water breakthrough occurred early, resulting in a rapid increase in water cut.

The schematic diagrams of the well patterns illustrate the oil–water distribution after 15 years of production at a 300 m × 300 m area with a permeability of 10 mD (Figure 8, Figure 9 and Figure 10). The water flooding sweep effect of the five-point well pattern was the best. The water flooding direction of the inverted nine-spot and the inverted nine-spot pattern mainly pointed to the area where the reservoir pressure dropped obviously, and the sweep effect was lower than that of the five-point pattern.

For the Reservoir A with an average permeability of approximately 12.28 mD, based on the 3D maps, three development options could be considered:

• Five-spot well pattern, a well spacing of 350 m, an oil production rate of 2%;
• Inverted seven-spot well pattern, a well spacing of 350 m, an oil production rate of 2%;
• Inverted nine-spot well pattern, a well spacing of 350 m, an oil production rate of 2%.

The five-spot well pattern had the widest recommended well spacing and the best economic benefits. Additionally, it had the highest oil recovery, the lowest water cut, and a comparable reservoir pressure maintenance level. Therefore, the five-spot well pattern was recommended.

3.2. Gas Flooding and Water Flooding Scheme Optimization

The capillary tube experiment results (Figure 11) show that the minimum miscibility pressure (MMP) of CO₂ is approximately around 27.23 MPa. In the case of N₂, even when the pressure was raised to over 40 MPa, miscibility was still not achieved. When the pressure increased, the increase in oil displacement efficiency became less significant. At excessively high pressures, there was a noticeable N₂ breakthrough phenomenon, leading to a rapid increase in the gas–oil ratio. This further confirmed the extreme difficulty of achieving miscibility or near-miscibility displacement with N₂ under reservoir conditions, highlighting the primary role of N₂ as a means to supplement reservoir energy.

The two schemes involving N₂ injection resulted in lower oil recovery compared to the other schemes (Figure 12); the main reason for this was that achieving miscibility between N₂ and oil under the current reservoir conditions was difficult.

Gas, under reservoir conditions, exhibited better injectivity and relative permeability compared to water. In the early stage of the N₂ flooding scheme, reservoir pressure was well maintained. However, when N₂ breakthrough occurred, a rapid decrease in pressure, a raise in water cut and a sharp reduction in oil production happened (Figure 13, Figure 14 and Figure 15).

Morever, the scheme involving CO₂ injection showed better reservoir pressure maintenance compared to schemes involving water injection (Figure 15). CO₂, under reservoir conditions, could achieve miscibility with crude oil, leading to a higher oil recovery.

3.3. Application Effects of Water Flooding and Gas Flooding Schemes in the Target Reservoir

The rock formations of Reservoir A exhibited hydrophilic properties, and the internal structure of the rock contained complex pore structures with varying pore throat sizes. The permeability of the water phase was largely governed by capillary forces, making water flooding less effective in impacting the crude oil within intricate and tiny pores compared to gas flooding, even N₂ flooding.

Among the water flooding strategies, cyclic water injection was slightly more favorable than continuous water flooding (Figure 16). This was mainly because cyclic water flooding could induce unstable pressure drops within the reservoir, creating unstable flow in layers with varying permeabilities, thus adjusting the injection–production system and improving water flooding efficiency.

For oil reservoirs implementing N₂ injection development, N₂ breakthrough occurred before water cut increased. This was primarily due to the superior N₂ permeability compared to crude oil. Following N₂ breakthrough, there was a decline in oil production. If the oil field maintained a steady production of a certain liquid volume daily, then with a decrease in crude oil production, the water cut would rise (Figure 17).

In terms of pressure maintenance, water flooding exhibited a distinct advantage over N₂ flooding in the mid-to-late development stages (Figure 18). As for the water–gas alternating schemes, both water-CO₂ alternating and water-N₂ alternating exhibited positive effects on development and were more cost-effective compared to gas injection. Taking into account factors such as the oil recovery, water cut, reservoir pressure maintenance, and economic benefit, water–gas alternating schemes were suitable for both homogeneous and heterogeneous reservoirs.

The final development scheme of Reservoir A was determined as follows: a five-spot well pattern, a well spacing of 350 m, an oil production rate of 2%, and a water–gas alternating flooding scheme.

3.4. The Utilization of Natural Energy

Due to the pressure condition of Reservoir A and economic benefit, simulations were conducted for depletion development periods of 4 months, 6 months, 8 months, 10 months, and 12 months in the target reservoir. From the simulation results, it is evident that the 8-month depletion development scheme obtained the highest oil recovery and the lowest water cut (Figure 19) and maintained reservoir pressure at a relatively high level (Figure 20). After 8 months of depleted development, the reservoir pressure coefficient was about 1.09.

3.5. Research Analyzation

The research process and important results have been summarized (

Table 2. Research summary.

Research	Result
Study on development mechanism of type A reservoir.	Low-permeability and high-pressure reservoirs are suitable for development at low production rates.
Water flooding scheme optimization and gas flooding research.	The water–air alternating scheme has positive effect on reducing water cut, maintaining formation pressure and enhancing oil recovery.
Verification of mechanism research conclusions.	The production mechanism of homogeneous reservoirs is mostly applicable to actual heterogeneous reservoirs.
Research on natural energy utilization.	It is more suitable to keep the reservoir pressure coefficient at about 1.09.

). The advantage of this study is that it directly reflects the production characteristics of reservoirs with different physical properties and development methods through the use of 3D maps and puts forward a reasonable method to select the suitable reservoir development mode based on the selection criterion of oil recovery, water cut, and reservoir pressure maintenance degree combined with economic evaluation. However, it is also limited to some extent because the actual oil field production conditions are dynamic changes, the actual geological characteristics of different reservoirs are also different, and the formation conditions are more complex. Before the exploration, the initial reservoir condition is not very clear. The optimization method of the production mode using 3D maps is undoubtedly convenient and effective. However, the specific production system should be adjusted to a certain extent with the actual production situation of the oil field in order to find the most suitable development mode of a reservoir itself and finally achieve the purpose of improving the oil recovery and saving economic costs.

In this study, the majority of experiments were designed using a single-factor control variable approach with parameter variations. There are still many development parameters awaiting optimization, such as optimizing the injection–production ratio, determining economically feasible well spacing for gas flooding, and assessing the applicability of advanced water injection strategies. After the optimization and screening of these influencing factors, it may provide a better scheme for oilfield development.

4. Conclusions

In this study, an optimized development pattern for high-pressure, low-permeability reservoirs was established, which could quickly determine the appropriate production mode for the reservoir during the initial production phase.

The poorer the reservoir permeability, the larger the well spacing and the slower the energy transfer, resulting in a faster decline in oil production. Low-permeability reservoirs were suitable for development with small well spacing and lower oil production rate. Based on the optimization pattern, it was concluded that high-pressure, low-permeability reservoirs with a permeability of 12.28 mD were best developed using a well spacing of 350 m with a five-spot well pattern at an oil production rate of 2%, which was validated in actual reservoirs. From the perspective of simulation results, 20 mD was a critical threshold for changes in oil–water production characteristics.

For homogeneous oil reservoirs, water flooding was more effective than N₂ displacement. N₂ was difficult to make miscible under stratigraphic conditions. N₂ displacement primarily supplemented reservoir energy. When N₂ broke through, it led to a rapid decline in reservoir pressure and oil production. Periodic water injection could create unstable pressure drops within the reservoir, promoting unstable flow in different permeable layers, and thus improving water flooding effectiveness to some extent.

CO₂ readily underwent miscible flooding under reservoir conditions, making it a preferred displacement media for low-permeability reservoir development. However, in terms of development effectiveness and cost, the water–gas alternating injection scheme is the most optimal.

High-pressure reservoirs could be challenging for initial water/gas injection due to their high initial reservoir pressure. Therefore, utilizing natural energy for a certain period of depletion development was advisable. For Reservoir A, the utilization of natural energy for development should be controlled to approximately 8 months, and reservoir pressure coefficient should be controlled at about 1.09.