Study on water injection intensity classification of irregular horizontal-vertical well groups

doi:10.21203/rs.3.rs-3333609/v1

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Study on water injection intensity classification of irregular horizontal-vertical well groups

https://doi.org/10.21203/rs.3.rs-3333609/v1

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Horizontal wells with artificial fractures have been proven to be an effective method to develop tight reservoirs. However, inappropriate water injection might lead to non-uniform waterflooding in the group of horizontal producers and vertical injectors. Therefore, the objective of the current study is to optimize the flowrate of vertical injectors in the combination of horizontal and vertical wells. First, a series of numerical models with different relative positions of horizontal and vertical well were built in a tight reservoir. Through numerical simulation and three-dimension (3D) visualization technique, the controlling area of the horizontal well was divided into three areas where injectors follow different flowrates to increase the sweep area and avoid water breakthrough. Then, a numerical model with one horizontal well and three vertical wells was established to study the flowrate ratio between the injectors from different controlling areas. Simulation results show that three injectors with 6:3:1 of flowrate ratio can obtain an extra 2997.6 m³ cumulative oil production than that with 1:1:1 of flowrate ratio.

Tight reservoirs

Water injection

Non-uniform waterflooding

Numerical simulation

Flowrate ratio

With the decline of high-quality and easy-to-exploit oil resources, tight reservoirs have been regarded as an important alternative to guarantee a continuing supply of crude oil. (Hu et al. 2018) The horizontal well with volume fracturing stimulation is an effective technology to develop tight reservoirs. (Yekeen et al. 2019) The utilization of horizontal wells significantly increases oil production that cannot be reached through a single vertical well. These wells are intercepted by artificial cracks that provide a more advantageous flow path of crude oil. However, as the development continues, the oil production of horizontal wells always decreases dramatically with the depletion of formation pressure. (Yu et al. 2019) To supply the formation energy, petroleum engineers proposed a series of technologies, including waterflooding, gas flooding, water-alternating-gas (WAG) flooding, water injection huff-n-puff and gas huff-n-puff. (Jackson et al. 2016) A lot of laboratory experiments and numerical simulations have provided considerable evidence that gas injection, especially CO₂ injection, is a promising enhanced oil recovery (EOR) method because of its positive attributes, such as good injection capacity and miscibility with oil. However, as CO₂ sources are costly, water injection is still the most commonly used method.

Water flooding is an effective and economic technique to improve oil recovery following primary production for conventional reservoirs. However, strong reservoir heterogeneity caused by natural and artificial fractures always leads to a low sweep efficiency of injected water in tight reservoirs. To exploit more oil through water flooding, researchers mainly focus on the optimization of well patterns. (Li et al. 2015, Rongze et al. 2012) The diamond-shaped inverted nine-spot well pattern has been proven to be superior to other well patterns in developing fractured tight reservoirs. Nevertheless, the well patterns of oil fields are often irregular.(Kou, Wang, et al. 2022, Kou, Zhang, et al. 2022, Wang et al. 2022) One of the typical irregular horizontal and vertical combined well groups of Fuxian oilfield (Ordos Basin, China) is shown in Fig. 1. The newly drilled horizontal well is not only a production well but also an exploratory well for the purpose of understanding the geology of that area. Thus, the space between newly drilled horizontal wells is relatively large. Meanwhile, there are often only 1 ~ 3 water injection wells around a horizontal well due to cost constraints. And it is impractical to change the well pattern by drilling new wells in the contemporary low oil price era. Therefore, it is extremely important to determine suitable injection parameters to improve oil recovery under the existing irregular well patterns.

According to the available literature in this research area, flowrates of different vertical injectors were always kept the same in a well group. However, flowrates of different vertical injectors should not be the same in irregular well groups due to different relative positions of vertical injectors and horizontal producers.(Yue et al. 2018, Strickland and Crawford 1991) To the best of our knowledge, limited literature focuses on the optimization of flowrate in irregular well groups. Therefore, this study employed streamline simulation and 3D visualization technology to optimize the injection parameters of irregular well groups.

In this paper, twenty-two cases with different relative positions of vertical injectors and horizontal producer were first studied. According to the simulation results, the controlling area of horizontal well was divided into three areas where vertical injectors should perform different flowrates. Then, a typical irregular well group with one horizontal well and three vertical wells was studied to obtain the flowrate ratio between the injectors from different areas. In the end, analyses of the streamline simulation were conducted to illustrate the mechanism of the difference of sweep efficiency caused by different flowrate ratios between the injectors.

To optimize the injection parameters for the horizontal-vertical well group, a conceptual model with one vertical injection well and one horizontal production well was established. The surrounding of the horizontal well was fractured. The formation after fracturing can be represented by the combination of fracture systems and matrix systems. The conceptual model is shown in Fig. 2.

As shown in Fig. 2, the conceptual model can be divided into four regions (Ⅰ, Ⅱ, Ⅲ and Ⅳ). As all four regions are central symmetry, only one region (Region I) was selected to study the injection parameters for the horizontal-vertical well group. Region Ⅰ includes both fracture and matrix systems. The water injection well W_i was placed in the conceptual model. Total 22 kinds of one injection and one production groups with the different relative positions of horizontal well and vertical well can be obtained.

The parameters of a typical tight reservoir in the Fuxian oilfield (Ordos Basin, China) were presented in Table 1. The component model of Eclipse software was used to simulate the waterflooding process.

Table 1

Key simulation parameters used in the model.
Items	Values
The length of horizontal well/m	800
Average porosity	0.15
Average permeability of matrix region/mD	0.23
Average permeability of fracturing region/mD	200
Fracture width/cm	20
Fracture half-length/m	250

The mesh generation for the tight reservoir is shown in Fig. 3. The depth of the top layer of the reservoir is 1425 m, the grid number is 140×80×4, and each grid volume is 10 m× 10 m× 10 m.

In this study, the economic limit was proposed to help to study the classification of the water injection area. The economic limit of horizontal well refers to a balance between the profits yielded by the oil production and the investments on the initial costs, personnel management, and equipment maintenance. In the Fuxian oilfield, it would reach the economic limit when the oil production rate lowers than 3 m³/d. The time, by which the production of horizontal wells reach the economic limit, is called the “limit time”.

The streamline simulations of 22 one-injection-one-production cases were conducted to classify the water injection area in this section. In these cases, the horizontal well was developed for 300 days without energy supplement, and then water flooding was carried out. The injection-production ratio was set as 1.1:1. To ensure the economic limit can be reached in all of models, the simulation period was set as 6100 days. In order to investigate the effect of different relative locations between vertical and horizontal wells on the oil recovery of the well groups, we carried out the plane interpolation processing on the data of production time, cumulative oil production, and water cut of 22 streamline models upon reaching the economic limits. Then the results were displayed in 3D visualization with “Matplotlib”. The simulation results including limit time, cumulative oil production and water cut are shown in Figs. 4–6. According to the statistical analysis of the simulation results, the relative location between the water-injection well and horizontal well had a huge impact on production. The shorter the distance between the vertical well and fracturing zone, the higher water cut, shorter limit time, and lower cumulative oil production would be obtained in the horizontal well. And in the direction perpendicular to the horizontal well, as the distance between the vertical well and the horizontal wellbore increases, the development effect increases monotonically; in the direction parallel to the horizontal well, the development effect displays a trend that it firstly falls and then rises.

The distribution of formation pressure at the end of depletion development has a significant impact on the water-injection response. As inferred from Fig. 7, the injected water could easily sweep the fracturing zone due to the large decrease of the formation pressure in the fracturing zone. Figure 8 shows that the streamline is densely distributed at the position perpendicular to the wellbore in the initial period, while the opposite trend could be observed at the end of the depletion development. However, the channeling path can easily form near the fracturing zone.(Ishibashi et al. 2019) Therefore, the injection of a large amount of water in the nearby areas of the fractured zone could lead to low oil recovery, although the formation pressure in the areas far from the fracturing zone remains high. To increase the controlled reserves by the horizontal well, we need to increase the sweep efficiency through water injection. And a higher water-injection intensity can be applied to promote the oil displacement effect far from the fracturing zone.

By making a plane projection of economic limit (Fig. 4) and completing it according to the principle of central symmetry, the classification diagram of water injection regions (Fig. 9) could be obtained. It shows that the region around the horizontal well can be divided into three water-injection areas according to economic limit. And lowering the water injection intensity in region #3 or increasing the volumetric flowrate of injected water in region #1 is beneficial to enhance the effect of water flooding.

4.1 Water injection ratio coefficient optimization

As shown in Fig. 10, a typical irregular horizontal-vertical well group is established in this section to determine the water injection ratio coefficient of each injection well. To optimize the water injection ratio coefficient, a series of numerical simulations were conducted according to the twelve sets of ratio coefficients (see Table 2). In this numerical simulation, the horizontal well was developed for 300 days without energy supplement, and then water flooding was carried out for 5800 days at the injection-production ratio of 1.1. The cumulative oil production, water cut and production rate were employed to investigate the water injection ratio coefficient. The simulation results are shown in Figs. 11–13.

Table 2

Injection ratio coefficient (IRC).
Number/ #	IRC/ R₁	IRC/ R₂	IRC/ R₃
1	7.5	1.5	1
2	7	2	1
3	6.5	2.5	1
4	6	3	1
5	5.5	3.5	1
6	5	4	1
7	5.5	2.5	2
8	5	3	2
9	4.5	3.5	2
10	4.5	3	2.5
11	4	3.5	2.5
12	3.4	3.3	3.3

As shown in Fig. 11, the highest cumulative oil production after 6,100 days can be achieved with the water-injection ratio coefficient of combination #4, and the cumulative oil production is 33967.08 m³, which is 2997.6 m³ higher than that the combination #12 with a balanced water-injection ratio. Injection wells in region #1 not only supplemented formation energy but also displaced the remaining oil after the depletion development. So, we can increase the water-injection ratio coefficient of region #1 injection wells to get more oil production. Because the Region #3 is closer to the fracturing area of the horizontal well, the formation energy in this area is severely deficient after depletion development. If excessive water is injected into region #3, water channeling would be occurred along with fractures. It would reduce the sweep efficiency and affect the displacement of the remaining oil. Therefore, the injection intensities in region #3 should be reduced. As shown in Fig. 12, the horizontal well reaches the high water cut period (water cut > 60%) till the 6100th days in all the 12 combinations. We can also find from Fig. 13 that the production rate in all of the 12 combinations is nearly the same. Therefore, the IRC should be set as 6:3:1 to yield the high oil recovery.

4.2 Mechanism analysis of injection intensities classification

To investigate the mechanism of injection intensities classification, streamline distribution under 12 water injection ratio coefficients are simulated by FrontSim (see Fig. 14). The distribution range of streamline reflects the effect of water flooding. The density of streamline reflects the sweep efficiency of water flooding. The denser streamline reflects the higher sweep efficiency.(Nelson et al. 2018)

As can be seen from Fig. 14, the distribution of streamlines is approximately the same under 12 kinds of water injection ratio coefficients. It indicates that the classification of water injection intensities has little effect on water flooding controlled areas. In Figs. 14(1) and 14(2), streamlines are dense around I1, which shows that the reservoir displacement around I1 is adequate under high water injection intensities. However, the streamlines near I2 and I3 are very sparse, which means the sweep efficiency of water flooding is relatively low. For Figs. 14(3), 14(4) and 14(5), the streamlines near horizontal well and water injection wells are very dense, which indicates that the sweep efficiency is improved and the water flooding effect is better under these three water injection ratio coefficients. Compared with other combinations, the streamline distribution of combination 4 (IRC = 6:3:1) is denser in the central area of horizontal well, which indicates that it effectively supplements energy to the central area of horizontal well and improves the effect of water injection development. For the combination #12 with balanced water injection, the controlled area of I1 is less than that of combination #4. And the water flooding front of I1 in combination #12 was far from the horizontal well in 6100th days, so the balanced water injection development effect is poor.

Combinations of #1 (IRC = 7.5:1.5:1), #4 (IRC = 6:3:1) and #12 (IRC = 1: 1: 1) were selected to show the streamline distribution at 2800 d and 4200 d (see Fig. 15). In combination #1, the water flooding front of I1 has reached the horizontal well in 2800 d. While, when the production reaches 4200 d, the water channeling in I1 would lead to the rapid increase in water cut. The water injection volume of each water injection well in combination #12 is almost the same, but due to the I2 and I3 being close to the fracturing zone and the formation energy in these two areas drops obviously after depletion development, a large pressure gradient is easy to form after water injection, which makes the water injection front of I2 and I3 wells reach the horizontal wells quickly. So, it cannot displace the oil effectively. In addition, due to insufficient water injection in Well I1, the front of water flooding moves slowly, which makes the streamline in the middle of the horizontal well sparse and fails to effectively supplement the formation energy in this area. In combination #4, the water injection ratio of each water injection well is relatively reasonable. At 2800 d, the water flooding front of wells I2 and I3 is close to the horizontal well. And we can get from the streamline distribution at 4200 d, the oil saturation around the horizontal well has not significantly decreased, which indicates that the injected water effectively displaces the crude oil in the reservoir to the production well without water channeling.

This study provides a classification method for water injection regions of irregular horizontal-vertical well groups. The necessity of water injection intensities classification is verified by the numerical simulation results of a typical irregular three-injection-one-production model, and the water injection ratio coefficients among water injection wells are optimized. The different water injection ratio coefficients were analyzed visually through streamline simulation. The major findings can be summarized as follows:

(1) The region around the horizontal well is divided into three areas. The water injection intensity in region #1 should be the highest and in region #3 should be the lowest.

(2) The results of classification are mainly affected by the distribution of pressure field and flow field after depletion development of the horizontal well.

(3) The necessity of water injection classification is verified by numerical simulation. When the IRC is equal to 6:3:1, the production is 2997.6 m³, higher than that of balanced water injection after 6100 days.

(4) The water injection intensity classification of irregular horizontal-vertical well groups could provide theoretical guidance for increasing formation energy and avoiding water breakthrough.

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No competing interests reported.

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Study on water injection intensity classification of irregular horizontal-vertical well groups

Status:

Version 1

Abstract

Figures

1. Introduction

2. Reservoir Modeling

3. Classification of Water Injection Area

4. Water Injection Ratio Coefficient Optimization and Mechanism Analysis

4.1 Water injection ratio coefficient optimization

4.2 Mechanism analysis of injection intensities classification

5. Conclusions

References

Additional Declarations

Status:

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Number/ #	IRC/ R₁	IRC/ R₂	IRC/ R₃
1	7.5	1.5	1
2	7	2	1
3	6.5	2.5	1
4	6	3	1
5	5.5	3.5	1
6	5	4	1
7	5.5	2.5	2
8	5	3	2
9	4.5	3.5	2
10	4.5	3	2.5
11	4	3.5	2.5
12	3.4	3.3	3.3

Number/ #	IRC/ R₁	IRC/ R₂	IRC/ R₃
1	7.5	1.5	1
2	7	2	1
3	6.5	2.5	1
4	6	3	1
5	5.5	3.5	1
6	5	4	1
7	5.5	2.5	2
8	5	3	2
9	4.5	3.5	2
10	4.5	3	2.5
11	4	3.5	2.5
12	3.4	3.3	3.3

Number/ #	IRC/ R₁	IRC/ R₂	IRC/ R₃
1	7.5	1.5	1
2	7	2	1
3	6.5	2.5	1
4	6	3	1
5	5.5	3.5	1
6	5	4	1
7	5.5	2.5	2
8	5	3	2
9	4.5	3.5	2
10	4.5	3	2.5
11	4	3.5	2.5
12	3.4	3.3	3.3