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Numerical Study of Simultaneous Multiple Fracture Propagation in Changning Shale Gas Field

Figure 1. Three transverse fractures with a uniform spacing of 23.3 m in a single stage.

Effect of Injection Rate

The injection rate is another important factor for affecting hydraulic fracturing treatments. Additionally, we kept other parameters the same as the base case and investigated the effects of different injection rates on the fracture geometry (Figure 7 and Table 4). Four injection rates were considered: 10 m3/min, 12 m3/min, 14 m3/min and 16 m3/min. Since the injection time for all of the cases was the same, more fluid volume was injected for the larger injection rate.

Figure 7 shows that a more uniform fracture geometry was achieved for the larger injection rate. The simulation results demonstrate that a higher injection rate is better for promoting a uniform fluid volume distribution and an even growth for each cluster in the Changning shale gas field. This is because that larger injection rate can mitigate stress shadow effects and generate a higher perforation friction pressure drop. Consequently, the injection rate of the Changning shale gas field should be increased to improve the cluster efficiency.

Figure 7. Effects of different injection rates on the fracture geometry: (a) 10 m3/min; (b) 12 m3/min; (c) 14 m3/min; and (d) 16 m3/min.
Figure 7. Effects of different injection rates on the fracture geometry: (a) 10 m3/min; (b) 12 m3/min; (c) 14 m3/min; and (d) 16 m3/min.

Table 4. The results of fracture length affected by different injection rates.
Table 4. The results of fracture length affected by different injection rates.

Effect of Fluid Viscosity

We studied the effects of different fluid viscosities on the fracture geometry, and the simulation results are shown in Figure 8. The other parameters are the same as those of the base case. The three different viscosities of the injection fluid are, respectively, 2.0 mPa·s, 10 mPa·s and 24 mPa·s. An injection fluid with a larger viscosity created a higher fluid pressure within the fracture and a wider fracture width (Figure 8 and Table 5).

A higher fluid pressure generated stronger stress shadow effects, resulting in a larger variation of fluid distribution between perforation clusters. Figure 8 illustrates that the length of the middle fracture is reduced by 40.6%, and the width increases by 76%, when the fluid viscosity increases from 2.0 mPa·s to 24 mPa·s. For that reason, the viscosity of the injection fluid should be decreased to 2.0 mPa·s in the Changning shale gas field.

Figure 8. Effect of fluid viscosity on the fracture geometry: (a) 2 mPa·s; (b) 3.5 mPa·s; (c) 10 mPa·s; and (d) 24 mPa·s.
Figure 8. Effect of fluid viscosity on the fracture geometry: (a) 2 mPa·s; (b) 3.5 mPa·s; (c) 10 mPa·s; and (d) 24 mPa·s.

Table 5. The results of fracture length affected by different fluid viscosities.
Table 5. The results of fracture length affected by different fluid viscosities.

Effect of Number of Fractures Within the Stage

The number of fractures within the stage is an important factor of hydraulic fracturing treatments, which is the most effective way to increase production in the Haynesville [14]. Therefore, we studied the impacts of different cluster numbers on the fracture geometry in a single stage. Under the condition of the fixed stage length of 70 m, the cluster number of four cases is, respectively, 2, 3, 4 and 5, while the other parameters are the same as the base case. The simulation results are shown in Figure 9 and Table 6.

They illustrate that as the cluster number within the stage increases, the cluster spacing decreases, and the stress shadow effects increase, leading to a longer total fracture length and shorter average fracture width. The optimal number of clusters in a single stage needs to be determined in combination with the production simulation and economic evaluation. However, according to the simulation results, if more than 4 clusters within the stage are used, one needs to utilize the intrastage diversion techniques [23,24] to enhance cluster efficiency in the Changning shale gas field.

Figure 9. Effects of different numbers of fracture within the stage on the fracture geometry: (a) 2; (b) 3; (c) 4; and (d) 5.

Figure 9. Effects of different numbers of fracture within the stage on the fracture geometry: (a) 2; (b) 3; (c) 4; and (d) 5.

Table 6. The results of fracture length affected by different number of fractures within the stage.
Table 6. The results of fracture length affected by different number of fractures within the stage.

Discussions

In order to evaluate the effects of the fracture spacing, perforating number, injection rate, fluid viscosity, and number of fractures within the stage on the fracture geometry in the Changning shale gas field, we defined a deviation of the normalized fracture length [25]. This sequence can indicate the main controlling factors for the effectiveness of fracture treatments. First, according to the basic input parameters, the average fracture length in the example is calculated. Then, we calculated the deviation of the three fractures. In the same way, we calculated the maximum and minimum deviation corresponding to the maximum and minimum values of each uncertain parameter.

Finally, we sorted each uncertain parameter according to the maximum and minimum deviation values. Based on the sorting result and the deviation of the normalized fracture length, the Tornado plot (Figure 10) was obtained. The x-axis is the calculated deviation of the normalized fracture length and represents the effects of uncertain parameters on the uniformity of the fracture growth. The order of uncertain parameters in the y-axis was determined by the absolute difference between the maximum and minimum deviation of the normalized fracture length. The green bar represented a positive effect and the black bar represented a negative effect.

The middle mark represented the deviation of the normalized fracture length of the base case. The Tornado plot shows that the number of fractures within the stage is the most important parameter for affecting the fracture geometry in the Changning shale gas field. A larger variation of fracture geometry will be created with either the increasing number of fractures, the decreasing flow rate, the increasing perforating number or the increasing fluid viscosity. The fracture spacing has a relatively smaller impact on the fracture geometry.

It should be mentioned that the spatial variations of the stress state, natural fractures and near wellbore tortuosity are not considered in this study, but will be examined in our future work. Therefore, we should improve the number of fractures in the stage with the intrastage diversion techniques. In addition, 16 m3/min of flow rate, 12 perforations for each cluster and an injection fluid with 2.0 mPa·s are better for improving the effectiveness of the stimulation treatments in the Changning shale gas field.

Figure 10. Rank of five uncertain parameters on the deviation of the normalized fracture length.
Figure 10. Rank of five uncertain parameters on the deviation of the normalized fracture length.

Conclusions

We applied a complex fracture propagation model to simulate multiple fracture propagation in the Changning shale gas field. The effects of the fracture spacing, perforating number, injection rate, fluid viscosity, and number of fractures within the stage on the fracture geometry were investigated based on field data from the Longmaxi shale formation in the Changning shale gas reservoir. The following conclusions can be drawn from this study:

(1) The main factors for controlling the cluster efficiency in the Changning shale gas field are the cluster numbers, the perforation density, the injection rate, and the liquid viscosity.

(2) Hydraulic fracture treatments with more than four clusters per stage, a lower injection rate, larger perforating number, larger viscosity fluid, and closer fracture spacing can result in an increasing gap between the inner fracture and outer fractures, and they will likely exhibit a bad production performance.

(3) This study provides a better understanding of the way to appropriately optimize a hydraulic fracturing treatment design which can increase the effective fracture number and promote the shale gas well performance in Changning.

Author Contributions

Conceptualization, J.X. and H.H.; methodology and investigation W.Y. and K.W.; writing—original draft preparation, H.H.; writing—review and editing, Y.S. and Y.F.; project administration, J.C.; funding acquisition, Y.S. and Y.F.

Funding

This research was funded by “National Science and Technology Major Project of China, grant number 2016ZX05023-005-00” and “The Chinese Academy of Engineering Key Consulting Research Project, grant number 2018-XZ-20” and “Major Science and Technology Special Project of CNPC, grant number 2016E-0612”.

Conflicts of Interest

The authors declare no conflict of interest.

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Contact Authors:

[email protected] (J.X.); [email protected] (Y.S.); [email protected] (Y.F.); [email protected] (J.C.)

[email protected]

[email protected] (H.H.); [email protected] (K.W.);

Tel.: +86-028-86018593 (H.H.); +86-010-5125652857 (K.W.)

© 2019 by the authors. This article is an open access article distributed under the terms and conditions of the Creative Commons Attribution (CC BY) license (http://creativecommons.org/licenses/by/4.0/).

Emanuel Martin
Emanuel Martin is a Petroleum Engineer graduate from the Faculty of Engineering and a musician educate in the Arts Faculty at National University of Cuyo. In an independent way he’s researching about shale gas & tight oil and building this website to spread the scientist knowledge of the shale industry.
http://www.allaboutshale.com

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