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Numerical simulation of operation performance on production and injection of a double well geothermal system in Kailu Basin, Inner Mongolia
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Abstract: Inner Mongolia is abundant in geothermal resources, but the development and utilization of medium-depth geothermal resources for clean heating in winter is still in the preliminary stage compared with the neighboring provinces. In this paper, a recently developed geothermal heating system using the Mesozoic sandstone reservoirs in Baokang of Kailu Basin, Eastern Inner Mongolia was investigated, a three-dimensional geological model of a pair of production and injection well was established, and numerical simulations on the long term operation performance were conducted and verified by pumping test and water level recovery test data. The effects of flow rates, the direction of wells, injection temperature and ratios on the flow field and water level in the thermal reservoir were analyzed. The results show that considering a 30-year operation period and a production rate from 90 m3/h to 110 m3/h, the optimum well spacing can be increased from 225 m to 245 m, with an average value of 235 m. With the decrease of the injection temperature, the cold front of the injection water has an increasing influence on the temperature in the production well. A complete injection or the principle of production according to injection is recommended in order to maintain the long-term operation stability. In addition, the location of the injection well should be arranged in the downstream of the natural flow field. The present results can provide a useful guide for the optimum design and performance prediction of geothermal wells, thus maintaining the production and injection balance and promoting the sustainable development and utilization of medium-depth and deep geothermal resources.
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Figure 1. Geological schematic map in the south of Songliao Basin (modified from Qin et al. 2015)
Figure 5. Variations of temperature (a-d) and water head (e-h) in the production well under different well spacing during the 30-year operation
Figure 6. The temperature distribution in thermal reservoir under different well spacing after the 30-year operation
Figure 7. Variations of temperature and water head in the production well under different flow rates
Figure 8. Variations of temperature and water head in the production well under different injection well orientations
Figure 9. Variations of temperature and water head in the production well under different injection temperatures
Figure 10. Influence radius of the cold front of injection water under different injection temperatures
Figure 11. Variations of temperature and water head in the production well under different injection ratios
Table 1. Hydrogeological and thermophysical parameters for simulations
Thermal reservoir Hydraulic conductivity (m/d) Rock Fluid Kx Ky Kz Porosity Heat capacity
(MJ/m3K)Thermal conductivity
(W/mK)Heat capacity
(MJ/m3K)Thermal conductivity
(W/mK)K2sf 0.001 0.001 0.0001 0.019 2.5 2.0 4.18 0.65 K2qs 0.024 0.024 0.0024 0.274 2.5 2.5 4.18 0.65 K1f 0.068 0.068 0.0068 0.290 2.5 2.5 4.18 0.65 K1sh 0.153 0.153 0.0153 0.234 2.0 2.5 4.18 0.65 K1jf 0.078 0.078 0.0078 0.177 2.5 3.0 4.18 0.65 
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Table 2. Simulation scenarios (elapsed time: 30 a)
No Production flow(m3/h) Spacing between wells(m) Injection temperature(℃) Injection ratio(%) 1 90,100,110 - 20 100 2 90 225 20 100 3 90 225 10, 15, 20, 25, 30, 35 100 4 90 225 20 0, 25, 50, 75, 100
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Table 3. Geothermal water pumping test results
No Water head (m) Water drop (m) Flow rate
(m3/h)Duration
(h)Water temperature
(℃)1 11.96 11.96 15.653 24 35 2 11.96 29.53 36.305 48 41 3 11.96 47.90 58.754 48 42 4 11.96 72.50 89.514 168 42
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Table 4. Optimum well spacing under different flow rates
No Elapsed time(a) Heat breakthrough temperature drop(℃) Optimum wells spacing (m) 90 m3/h 100 m3/h 110 m3/h 1 30 2 175 200 210 2 30 1 200 210 220 3 30 0.5 210 220 230 4 30 0.2 225 235 245 5 30 0 275 285 300
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