Abstract
Hydraulic fracturing and acidizing are the primary ways of reservoir stimulation for tight sandstone gas reservoir. The supplement of formation energy and complex fracture network induced by stimulation are favorable contributors to increase production. However, since the factors affecting the EUR are various, gas production is not always positively related to stimulation due to the possible formation damage. Specifically, the production of a well from deep Tarim basin was found to reduce after several ways of stimulation. In this study, a numerical model coupled the gas flow in reservoir, including the matrix and natural fractures, with that in the primary and secondary hydraulic fractures was established to describe the relationship between multi-scale systems. In addition, history match and production capacity prediction methods were used to determine the effectiveness of each stimulation way. The numerical results of the gas production and oil pressure were matched with the field data and the reason for low production was analyzed. Results indicate that production increases after each stimulation, but the effect of stimulation get worse and worse after superposition of these stimulations. The reason may results from the accumulative damage to the formation and the later stimulation may not be able to effectively expand the control volume (fracture half length) and hardly improve the conductivity of hydraulic fractures (fracture width). The study provides enlightenment on whether a secondary or more times stimulations are proper after the first stimulation.
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Abbreviations
- \(m_{m}\) :
-
= gas mass in matrix, kg
- \(m_{nf}\) :
-
= gas mass in natural fractures, kg
- \(u_{m}\) :
-
= gas velocity in matrix, m3/s
- \(u_{nf}\) :
-
= gas velocity in natural fractures, m3/s
- \(t\) :
-
= time, s
- \(Q_{m - nf}\) :
-
= mass exchange rate of gas between matrix and natural fracture, kg/s
- \(\rho\) :
-
= density, kg/m3
- \(p_{m}\) :
-
= matrix pressure, MPa
- \(p_{nf}\) :
-
= natural fracture pressure, MPa
- \(\mu\) :
-
= viscosity, mPa.s
- \(\sigma_{m - nf}\) :
-
= shape factor, m2
- \(m_{pf}\) :
-
= gas mass in primary fractures, kg
- \(m_{sf}\) :
-
= gas mass in secondary fractures, kg
- \(u_{pf}\) :
-
= gas velocity in primary fractures, m3/s
- \(u_{sf}\) :
-
= gas velocity in secondary fractures, m3/s
- \(k\) :
-
= absolute permeability, mD
- \(p_{i}\) :
-
= initial reservoir pressure, MPa
- \(h\) :
-
= reservoir thickness, m
- \(\phi\) :
-
= porosity, %
- \(T\) :
-
= temperature, ℃
- \(x_{f}\) :
-
= fracture half length, m
- \(x_{pf}\) :
-
= propped fracture half length, m
- \(h_{f}\) :
-
= fracture height, m
- \(\rho_{p}\) :
-
= proppant concentration, kg/m3
- \(\omega_{a}\) :
-
= average fracture width, mm
- \(\omega_{m}\) :
-
= maximum fracture width, mm
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Qu, Hy., Hu, Jw., Zhou, Fj., Zhong, Yc. (2021). Effect of Successional Reservoir Stimulation on the Production in Tight Gas Reservoir. In: Lin, J. (eds) Proceedings of the International Field Exploration and Development Conference 2020. IFEDC 2020. Springer Series in Geomechanics and Geoengineering. Springer, Singapore. https://doi.org/10.1007/978-981-16-0761-5_299
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DOI: https://doi.org/10.1007/978-981-16-0761-5_299
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