Optimization Study of Injection and Production Parameters for Shallow- and Thin-Layer Heavy Oil Reservoirs with Nitrogen Foam-Assisted Steam Flooding

Abstract

Shallow- and thin-layer heavy oil reservoirs are characterized by their shallow burial, thin thickness, high viscosity, and scattered distribution. After years of steam injection development, several issues have emerged, including a highly comprehensive water cut in the reservoir and serious steam channeling. Therefore, there is an urgent need to change the development approach to enhance crude oil recovery. It has been discovered that developing heavy oil reservoirs through nitrogen foam-assisted steam flooding can effectively address the challenges encountered in pure steam development. This paper takes H Oilfield Block A as a case study, analyzes the geological characteristics and development status of the reservoir in this block, and predicts the recovery of steam injection development in this block using the injection-production characteristic curve method. Furthermore, by establishing a reservoir geological model and fitting it to the historical behavior of the target reservoir, the nitrogen foam-assisted steam flooding injection and production parameters were optimized. The optimal parameters are as follows: optimal steam injection intensity of 2.0 t/(d·ha·m), optimal production/injection ratio of 1.2:1, optimal nitrogen foam slug injection volume of 0.15 PV, optimal nitrogen/steam ratio of 2:1, and intermittent injection between 3 and 4 foam slugs. It is anticipated that this optimized scheme will result in a predicted increase in final recovery of 13.55%. The findings of this study hold significant importance in guiding the application of nitrogen foam-assisted steam flooding in shallow and thin heavy oil reservoirs.

1. Introduction

China possesses abundant heavy oil resources, ranking as the fourth-largest country in the world in terms of heavy oil reserves [1,2]. Currently, a large number of heavy oil fields have been discovered in 15 large and medium-sized oil and gas-bearing basins and regions, primarily in the Liaohe Oilfield, Xinjiang Karamay Oilfield, Shengli Oilfield, and Henan Nanyang Oilfield [3]. The distribution of heavy oil fields in China is shown in Figure 1. Heavy oil and bitumen resources account for more than 20% of the total petroleum resources, with a proven reserve of 43.5 × 10⁸ t [1]. These resources are crucial for China’s strategic security and energy independence [4,5]. In recent years, the newly discovered heavy oil resources in China have exhibited declining quality characteristics, including shallow burial, thin reservoir thickness, high viscosity, and scattered distribution [6,7]. For these shallow- and thin-layer heavy oil resources, due to their high viscosity and fast heat dissipation in a thin layer, there is a low heat utilization efficiency [8,9,10,11]. After many years of steam injection development, phenomena such as high reservoir integrated water cut, serious steam channeling, lower oil/steam ratio, and dispersion of residual oil occur, which lead to poor development and a low degree of reservoir utilization [12]. Henceforth, it is imperative to change the development approach and improve recovery in order to ensure a steady and continuous growth in heavy oil production capacity [13,14].

It has been discovered that utilizing nitrogen foam-assisted steam flooding for the development of shallow- and thin-layer heavy oil reservoirs can effectively address the challenges encountered during pure steam injection development [15,16,17]. The primary mechanisms of nitrogen foam-assisted steam flooding can be summarized as follows: (1) Elevation of formation pressure: nitrogen, with its high compression and volume coefficients, plays a crucial role in elevating the formation pressure [18]. When steam and nitrogen are injected into the formation, nitrogen is compressed and stores energy under pressure. As production wells are produced, the formation pressure decreases, causing the steam to condense into hot water. Meanwhile, nitrogen rapidly expands in volume, driving the heated viscosity-reducing crude oil. With the continual decrease in the formation pressure, nitrogen continues to expand while stabilizing it effectively. This allows for better utilization of the steam function [19,20]. (2) Improve the range of steam coverage: nitrogen injected into the formation can quickly break forward, carrying high-temperature steam for transportation and heating crude oil in distant oil reservoirs through stored heat breakthrough. Additionally, injecting a high-temperature-resistant foaming agent into the formation with nitrogen can generate bubbles in the near-well zone, which seal channels due to the Jamin effect and force steam to enter reservoirs with poor physical properties, thereby expanding the range of steam action [21,22]. (3) Thermal insulation: under the influence of gravity, nitrogen forms a superimposed layer at the top of the oil reservoir, creating a “thermal insulation blanket” due to nitrogen’s low thermal conductivity. This blanket minimizes heat loss from the reservoir and enhances the thermal efficiency of steam utilization [23]. The schematic of nitrogen-assisted steam flooding is depicted in Figure 2.

The nitrogen foam-assisted steam flooding technology was field-applied to seven steam flooding well groups in Block 45 of the XinQian Oilfield in Henan Province [24]. The success rate of the process and the efficiency of measures were both 100%. After foam-assisted steam flooding, the oil/steam ratio increased from 0.1 to 0.15, resulting in a cumulative oil increase of 2501.9 t. In Block 40 of the Liaohe Oilfield, foam-assisted steam flooding experiments were conducted [25]. Prior to the experiments, injection parameters were optimized. Nitrogen foam was applied in six field tests across three steam injection well groups, with a total injection of 27.9 t of high-temperature foaming agent and 16.18 × 10⁴ m³ of nitrogen gas. The process success rate was 100%, and the cumulative oil increase was 1479 t. In the central area of Well Group 601 in the Chunfeng Oilfield, nitrogen foam-assisted steam injection was applied [26,27]. In the zone with bottom water invasion, nitrogen foam-assisted steam injection was used, reducing the average drainage period from the previous cycle by 8.3 days, decreasing the water cut by 32.2%, and increasing the cumulative oil production by 2606 t. In high-cycle zones, injecting nitrogen foam reduced the cycle water cut by 8.6% and increased cumulative oil production by 1668 t. This indicates that nitrogen foam can effectively enhance reservoir energy and block large-pore channels, achieving the goal of adjusting steam absorption profiles and playing a crucial role in increasing ultimate recovery [28].

This paper takes Block A in the H Oilfield as an example and conducts an analysis of the geological characteristics and development status of the reservoir in this block. Using the injection-production characteristic curve method, it predicts the recovery of steam injection development in this block. Furthermore, by establishing a geological reservoir model, it performs historical matching for the target reservoir. Finally, it designs and optimizes a nitrogen foam-assisted steam flooding scheme for Block A in the H Oilfield and determines the optimal parameters for nitrogen foam-assisted steam flooding. This research can serve as a reference for the optimization of nitrogen foam-assisted steam flooding development in shallow and thin heavy oil reservoirs, helping to address issues such as low post-development oil production and high water cut in shallow heavy oil reservoirs [29].

2. Methods

2.1. Analysis of the Development Effect

Using the analysis of key production indicators such as liquid production, oil production, water cut, and oil/steam ratio in shallow- and thin-layer heavy oil reservoirs within Block A, an evaluation was conducted to assess the development effectiveness. Furthermore, this study seeks out the problems encountered during the development process of this block and proposes corresponding measures to guide the formulation of a development plan for shallow- and thin-layer heavy oil reservoirs. Secondly, the injection-production characteristic curve method is utilized to predict the ultimate recovery of shallow- and thin-layer heavy oil reservoirs in Block A for pure steam development. The specific methods are as follows:

(1)

$\lg N_{s }-N_{p }$ Curve Method

Through linear regression analysis of the cumulative oil production and cumulative steam injection for the six well groups in the target area, it was found that there is a strong linear relationship between cumulative oil production and cumulative steam injection when plotted on a semi-logarithmic scale. The relationship can be expressed as:

$$\lg N_{s }=A+B{N}_p$$

(1)

$$N_{R }=\left(\lg \frac{1}{2.303B{R}_{os}}-A\right)/B_{.}$$

(2)

$$E_{R }=N_{R }/N$$

(3)

In the above equation, $N_{s }$ represents the cumulative steam injection volume in units of 10⁴ t. $N_p$ represents the cumulative oil production volume in units of 10⁴ t. $N_{R }$ represents the recoverable reserves in units of 10⁴ t. $R_{os}$ represents the ultimate oil/steam ratio. $E_{R }$ represents the ultimate recovery in percentage (%). $N$ represents the original reservoir reserves in units of 10⁴ t.

(2)

$N_{s }/N_{p }-N_{s }$ Curve Method

Through linear regression analysis of the ratio of the cumulative steam injection volume to cumulative oil production volume for the six well groups in the target area against the cumulative steam injection volume, it was found that there is a strong linear relationship between the ratio and cumulative steam injection volume when plotted on the coordinate axis. The relationship can be expressed as:

$$N_s/N_p=A+BN$$

(4)

$$N_p=(1-\sqrt{A{R}_{os}})/B$$

(5)

2.2. Numerical Simulation

Firstly, through the analysis of the geological characteristics and development status of the shallow and thin heavy oil reservoir in Block A, a numerical model was constructed using the Builder module of the reservoir numerical simulation software CMG [4,30]. Subsequently, historical fits were performed for reserves, oil production, and water cut, as well as oil production and water cut for individual wells, for the entire block. On this basis, the design optimization of steam injection and production parameters, as well as nitrogen foam-assisted steam drive parameters, was conducted to determine the optimal combination of nitrogen foam-assisted steam flooding parameters for the shallow and thin heavy oil reservoir in Block A.

3. Results and Discussion

3.1. Development Effect Evaluation

3.1.1. Reservoir Characteristics and Development Status

Production data statistics indicate that steam huff and puff development in this area began in 1991, and as of September 2021, the average steam huff and puff development in this region has exceeded 18 cycles. In this steam flooding development area, there are a total of 34 production wells and 6 injection wells connected in 6 well groups. Currently, the well group efficiency is at 65.3%, with an average daily oil production per well of 0.88 t and an oil/steam ratio of 0.11. The average water cut has exceeded 90%, as shown in Figure 3 and Figure 4. Block A has accumulated a steam injection volume of 580,300 t, a cumulative liquid production of 732,000 t, and a cumulative oil production of 177,300 t, with a verified recovery of 36.25% and remaining reserves of 311,700 t.

With the extension of the development period, the target area has exhibited a production status characterized by high water cuts and low oil production rates. Steam channeling has intensified, reservoir porosity and permeability have increased, and reservoir depletion has become severe. In some areas, a ‘Hot worm hole’ has formed, resulting in extremely low steam utilization efficiency. The heating radius and utilization radius are difficult to expand further, leading to a year-by-year decline in the oil-to-steam ratio and deteriorating development performance [31,32]. It is now imperative to change the development approach and enhance the ultimate oil recovery.

3.1.2. Recovery Prediction

(1)

$\lg N_{s }-N_{p }$ Curve Method

In Figure 5, where $A$ is 0.7503 and $B$ is 0.0583, the correlation coefficient $R^2$ is 0.9934. Assuming an ultimate oil/steam ratio of 0.1, these values can be applied to Equations (1) and (2), and the recoverable reserves $N_{R }$ for the six well groups in the target area can be determined. Substituting $N_{R }$ into Equation (3) provides the predicted recovery using steam injection, which is $E_{R }$ at 39.37%.

(2)

$N_{s }/N_{p }-N_{s }$ Curve Method

In Figure 6, where $A$ is 1.281 and $B$ is 0.0331, the correlation coefficient $R^2$ is 0.9897. Assuming an ultimate oil/steam ratio of 0.1, these values can be applied to Equations (4) and (5), and the recoverable reserves $N_{R }$ for the six well groups in the target area can be determined. Substituting $N_{R }$ into Equation (3) provides the predicted recovery using steam injection, which is $E_R$ at 39.67%.

Based on the two methods mentioned above, the ultimate recovery for continued pure steam development in Block A is 39.37% and 39.67%, respectively. Through an analysis of the current development status, the current recovery in Block A has already reached 36.25%. If pure steam development continues, the reservoir recovery will quickly approach its limit. Therefore, there is an urgent need to change the development method to utilize nitrogen foam-assisted steam drive for reservoir recovery so as to maximize the recovery of underground crude oil [33,34,35].

3.2. Numerical Simulation Results

3.2.1. Establishment of Reservoir Numerical Model

The research area is located on the eastern flank of the Gaozhuang South Nose structure, which is a monoclinal structure gradually uplifting from southeast to northwest. It has a strike of 145° and a dip angle of 9.8°, with its high points controlled by erosion surfaces and situated approximately 300 m away from the western fault [36]. The burial depth ranges from 160 to 230 m, and the effective oil layer thickness varies from 2 to 10 m. The average porosity is 32%, with an average permeability of 1.66 Darcy. The surface density of crude oil is 0.9535 g/cm³, and the viscosity of the undersaturated crude oil at reservoir temperature is 18,000 mPa·s. This reservoir is categorized as shallow, high-porosity, high-permeability, and extremely heavy oil reservoir.

Based on the fundamental data provided by the oilfield site and the geological characterization analysis of the target reservoir. A numerical simulation model was established for this shallow heavy oil block. The grid model is 87 × 40 × 16, with 87 layers in the i-direction, 40 layers in the j-direction, and 16 layers in the k-direction. Reservoir parameters are listed in

Table 1. Key parameters of the reservoir’s numerical model.

Parameters	Value
Burial Depth (m)	160–230
Effective Thickness (m)	2–10
Average Porosity (%)	32
Average Permeability (D)	1.66
Original Oil Saturation (%)	65
Original Formation Pressure (MPa)	2.2
Original Formation Temperature (°C)	24.9
Original Oil Saturation (g/cm3)	0.9535
Rock Compressibility (kPa−1)	1.56 × 10−5
Rock Volume Heat Capacity J·(m3·°C)−1	3.46 × 105
Rock Thermal Conductivity Coefficient J·(m·day·°C)−1	2.74 × 105
Rock Cap Bottom Layer Volume Heat Capacity J·(m3·°C)−1	2.35 × 106
Rock Cap Bottom Layer Thermal Conductivity J·(m·day·°C)−1	1.5 × 105

and shown in Figure 7 and Figure 8. The initial pressure, porosity, permeability, and oil saturation distribution in the three-dimensional numerical model can be seen in Figure 9.

3.2.2. Historical Fitting

The geological reserve fitting results for the shallow heavy oil reservoir in Block A are presented in

Table 2. Geological reserve fitting results.

Matching Index	Actual Reserves	Simulated Reserves	Error (%)
Reserves (×104 t)	48.9	49.5	1.2

. It can be observed in Table 2 that the geological reserve fitting error is less than 2%, indicating a good fit for the reserves.

The historical fitting results for the shallow heavy oil reservoir in Block A and a typical individual well are shown in Figure 10, Figure 11, Figure 12 and Figure 13. It can be observed in these figures that both the overall reservoir and the individual well exhibit good historical fitting results, which can be utilized for the optimization research of nitrogen foam-assisted steam flooding parameters in Block A.

3.2.3. Optimization of Parameters

(1)

Optimization of Steam Injection Intensity

In the steam flooding process, the steam injection intensity is a critically important parameter. An appropriate steam injection intensity ensures that a sufficient volume of steam permeates the reservoir, pushing the crude oil towards the wellbore and thereby achieving effective oil displacement. In this study, steam injection intensities of 1.4 t/(d·ha·m), 1.6 t/(d·ha·m), 1.8 t/(d·ha·m), 2.0 t/(d·ha·m), and 2.2 t/(d·ha·m) were simulated with an oil/steam ratio of 0.1 as the termination condition. The simulation results are presented in

Table 3. Simulation results for different steam injection intensities.

Steam Injection Intensity (t/(d·ha·m))	Stage Recovery (%)
1.4	3.34
1.6	4.01
1.8	5.12
2.0	6.82
2.2	6.12

and Figure 14. Based on the calculation results, it is evident that the stage oil recovery initially increases and then decreases with the increasing injection intensity. When the steam injection intensity is 2.0 t/(d·ha·m), the corresponding stage oil recovery is maximized, reaching 6.82%. This indicates that when the steam injection intensity reaches this level, it can promote a more uniform and efficient distribution of steam throughout the entire reservoir. This helps enhance the contact between steam and reservoir rocks, maximizing heat transfer and oil displacement efficiency. Therefore, the optimal steam injection intensity is 2.0 t/(d·m·ha).

(2)

Optimization of Injection/Production Ratio

A reasonable injection/production ratio ensures the even distribution of steam within the reservoir, preventing the formation of localized high-temperature zones and reducing the impact of temperature fluctuations on reservoir rock properties. Additionally, controlling the injection/production ratio helps prevent steam reinjection phenomenon, ensuring that effective oil displacement is achieved and minimizing resource wastage. Under the optimal steam injection intensity of 2.0 t/(d·ha·m), simulations were conducted for various injection/production ratios of 1, 1.1, 1.2, and 1.3, with an oil/steam ratio of 0.1 as the termination condition. The simulation results are presented in

Table 4. Simulation results for different injection/production ratios.

Production/Injection Ratio	Stage Recovery (%)
1	3.53
1.1	4.22
1.2	6.84
1.3	6.92

and Figure 15. Based on the calculations, it is observed that the stage oil recovery increases with an increase in the injection/production ratio. When the injection/production ratio is 1.3, the stage oil recovery reaches its highest value at 6.92%. At an injection/production ratio of 1.2, the stage oil recovery is 6.84%. It is worth noting that the increase in stage oil recovery from 1.2 to 1.3 is only 0.08%. Considering the current low level of pressure retention in the reservoir and the severe formation deficit, an excessive injection/production ratio could lead to a further reduction in formation pressure. Therefore, the optimal injection/production ratio is 1.2, as it results in the best development performance.

(3)

Optimization of Foam slug Size

According to the analysis of reservoir thermal connectivity and steam channeling volume after the development of thick oil reservoir steam injection in Block A, the steam channeling volume of the well group in Block A was calculated to be 35.1432 × 10⁴ m³. This value serves as the design basis for the quantity of nitrogen foam. The sizes of foam slug volumes in the well group of Block A were designed at different values, namely 0.05, 0.1, 0.15, 0.2, and 0.25 times the steam channeling volume, with an oil/steam ratio of 0.1 as the termination condition. The foaming agent’s mass concentration was maintained at 0.5 wt%, and the steam injection intensity and injection/production ratio were based on the optimization results mentioned earlier. The simulation results are presented in

Table 5. Simulation results for different foam slug sizes.

Foam Slug (PV)	Stage Recovery (%)
0.05	7.53
0.1	8.98
0.15	11.88
0.2	11.43
0.25	10.21

and Figure 16. Based on the calculations, the stage oil recovery increases with the foam slug volume, reaching a peak when the nitrogen injection volume is 0.15 times the steam channeling volume. Hence, it is observed that the most effective performance of nitrogen foam-assisted steam flooding is achieved when the nitrogen injection volume is set at 0.15 times the steam channeling volume. At this point, the foaming agent and nitrogen exhibit their maximum foaming capability, resulting in superior plugging of highly permeable channels. Therefore, a foam slug volume equivalent to 0.15 times the steam channeling volume is the most suitable choice for Block A.

(4)

Optimization of Nitrogen/Steam Ratio

The nitrogen/steam ratio was set at different values: 1:3, 1:2, 1:1, 2:1, and 3:1, with an oil/steam ratio of 0.1 as the termination condition. The foam slug size was kept at 0.15 times the steam channeling volume, the mass concentration of the foaming agent was maintained at 0.5 wt%, and the previously optimized values for steam injection intensity and injection/production ratio were utilized. The simulation results are presented in

Table 6. Simulation results for different nitrogen/steam ratios.

Nitrogen/Steam Ratio	Stage Recovery (%)
1:3	7.61
1:2	8.73
1:1	10.59
2:1	11.88
3:1	11.13

and Figure 17. Based on the simulation results, it is evident that as the gas–liquid ratio increases, the performance of nitrogen foam-assisted steam flooding improves. When the nitrogen/steam ratio is set at 2:1, the stage oil recovery reaches its maximum value, which is 11.88%. At this point, the nitrogen foam exhibits good stability and possesses strong water-blocking and oil-displacing capabilities. If the ratio is further increased, it may lead to premature gas breakthrough, which would have an adverse impact on the stability of the nitrogen foam. Therefore, the optimal nitrogen/steam ratio is 2:1.

(5)

Optimization of Injection Mode

While maintaining a consistent foaming agent concentration, nitrogen foam volume, steam injection intensity, and injection/production ratio, injection modes were tested individually, including continuous injection, two-foam-slug injection, three-foam-slug injection, and four-foam-slug injection. The termination condition was an oil/steam ratio of 0.1. The simulation results are presented in

Table 7. Simulation results for different foam slug injection modes.

Injection Mode	Stage Recovery (%)
Straight	11.88
Two Slug	12.32
Three Slug	13.55
Four Slug	13.43

and Figure 18. By comparing the results of these four simulation methods, it can be observed that dividing a single foam slug into 3–4 segments for intermittent injection produced the best oil recovery compared to the continuous injection mode. This injection mode allows nitrogen foam to be more uniformly distributed within the reservoir, reducing the impact of variations in underground reservoir permeability, and effectively preventing premature gas breakthrough. Therefore, regarding the injection mode, it is advisable to choose the intermittent injection mode with 3–4 foam slug segments.

4. Conclusions

This study analyzed the geological characteristics and development status of the A Block reservoir in the H Oilfield. Using the injection-production characteristic curve method, the study predicted the recovery of steam injection development in this block. The results indicated that if steam flooding development continues, the ultimate recovery will only reach 39.67%. Based on a geological model for the target reservoir block and a detailed historical fit, optimization of the parameters for nitrogen foam-assisted steam injection and production was performed. The optimal parameters identified are as follows: optimal steam injection intensity of 2.0 t/(d·ha·m), injection/production ratio of 1.2:1, optimal foam slug injection volume of 0.15 PV, optimal nitrogen/steam ratio of 2:1, and intermittent injection with 3–4 foam slug segments. The predicted result suggests that the final recovery will increase by 13.55% when using these optimal parameters. Through the optimization of key parameters in the process of nitrogen foam-assisted steam flooding, efficient, stable, and safe oil drive can be achieved. The study can provide a reference for the optimization of nitrogen foam-assisted steam flooding development in shallow- and thin-layer heavy oil reservoirs, which can help to solve the problems of low oil production and high water cut at the late stage of the development of shallow- and thin-layer heavy oil reservoirs.