Understanding the post-frac soaking process in multi-fractured shale gas-oil wells
Abstract view|0|times PDF download|0|times
Abstract
Multi-stage hydraulic-fracturing horizontal wells has revolutionized today’s oil and gas industry. Post-frac fluid soaking is essential for improving productivity of shale oil-gas wells. Optimization of soaking time is an open problem to solve in the petroleum industry. Understanding the post-frac soaking process is vitally important for solving the puzzle. Analytical solutions were developed in this study to describe the spontaneous imbibition processes in shale matrix and shale cracks during fluid soaking. Solutions show that the imbibition distance is directly proportional to the square root of imbibition time and the imbibition velocity is inversely proportional to the square root of imbibition time. The rate of spontaneous imbibition in shale cracks is much faster than that in shale matrix. Therefore, the optimum time for post-frac fluid soaking was further analyzed on the basis of the imbibition in shale cracks only. The solution was combined with pressure fall-off data to formulate a mathematical method for predicting the post-frac fluid soaking time required for the fluid to reach the mid-point between two adjacent hydraulic fractures. A case study with Tuscaloosa Marine Shale data suggests that the front of fluid imbibition should propagate 4 meters in 2 weeks and to 6 meters in 4 weeks. These numbers may be considered as the optimum times of post-frac fluid imbibition if the shale swell effect is negligible. Future research should quantify the effects of shale swelling on spontaneous imbibition so that the information can be incorporated in the soaking model to fully describe the imbibition process for better prediction of well productivity.
Document Type: Original article
Cited as: Guo, B., Wortman, P. Understanding the post-frac soaking process in multi-fractured shale gas-oil wells. Capillarity, 2024, 12(1): 6-16. https://doi.org/10.46690/capi.2024.07.02
Keywords
Full Text:
PDFReferences
Allen Jr., J. E., Meylan, M. A., Heitmuller, F. T. Determining hydrocarbon distribution using resistivity, Tuscaloosa Marine Shale, southwestern Mississippi. Gulf Coast Association of Geological Societies Transactions, 2014, 64: 41-57.
Anderson, R. L., Ratcliffe, I., Greenwell, H. C., et al. Clay swelling-a challenge in the oilfield. Earth-Science Reviews, 2010, 98(3-4): 201-216.
Besov, A., Tinni, A., Sondergeld, C., et al. Application of laboratory and field NMR to characterize the Tuscaloosa marine shale. Petrophysics, 2017, 58(3): 221-231.
Borrok, D. M., Yang, W., Wei, M., et al. Heterogeneity of the mineralogy and organic content of the Tuscaloosa Marine Shale. Marine and Petroleum Geology, 2019, 109: 717-731.
Cai, J. Some key issues and thoughts on spontaneous imbibition in porous media. Chinese Journal of Computational Physics, 2021, 38(5): 505-512. (in Chinese)
Cai, J., Perfect, E., Cheng, C. L., et al. Generalized modeling of spontaneous imbibition based on Hagen-Poiseuille flow in tortuous capillaries with variably shaped apertures. Langmuir, 2014, 30(18): 5142-5151.
Cai, J., Sun, S., Wang, H. Current advances in capillarity: Theories and applications. Capillarity, 2023, 7(2): 25-31.
Cai, J., Yu, B. Advances in studies of spontaneous imbibition in porous media. Advances in Mechanics, 2012, 42(6): 735-754. (in Chinese)
Chuprin, M., Naik Parrikar, P., Mokhtari, M., et al. Using digital image correlation for evaluating the impact of brine on swelling of heterogeneous shales. Rock Mechanics and Rock Engineering, 2022, 55(2): 1013-1035.
Crafton, J. W., Noe, S. L. Factors affecting early well productivity in six shale plays. Paper SPE 166101 Presented at the SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, 30 September-2 October, 2013.
Dutta, R., Lee, C., Odumabo, S., et al. Quantification of fracturing fluid migration due to spontaneous imbibition in fractured tight formations. Paper SPE 154939 Presented at the SPE Americas Unconventional Resources Conference, Pittsburgh, Pennsylvania, 5-7 June, 2012.
Ehlig-Economides, C. A., Economides, M. J. Water as proppant. Paper SPE 147603 Presented at the SPE Annual Technical Conference and Exhibition, Denver, Colorado, 30 October-2 November, 2011.
Guo, B., Shaibu, R., Hou, X. Crack propagation hypothesis and a model to calculate the optimum water-soaking period in shale gas/oil wells for maximizing well productivity. SPE Drilling & Completion, 2020, 35(4): 655-667.
Guo, B., Yang, X. Use of a new analytical model to match production data and identify opportunities to maximize well productivity in the Tuscaloosa Marine Shale reservoir. SPE Production & Operations, 2019, 34(4): 770-780.
Habibi, A., Binazadeh, M., Dehghanpour, H., et al. Advances in understanding wettability of tight oil formations. Paper SPE 175157 Presented at the SPE Annual Technical Conference and Exhibition, Houston, Texas, 28-30 September, 2015.
Hackley, P. C., Enomoto, C. B., Valentine, B. J., et al. Assessment of undiscovered continuous oil and gas resources in the Upper Cretaceous Tuscaloosa marine shale of the U.S. Gulf Coast, 2018. 2018-3043, 2018.
Handy, L. L. Determination of effective capillary pressures for porous media from imbibition data. Transactions of the AIME. 1960, 219(1): 75-80.
Kolodzie Jr., S. Analysis of pore throat size and use of the waxman-smits equation to determine OOIP in Spindle Field, Colorado. Paper SPE 9382 Presented at the SPE Annual Technical Conference and Exhibition, Dallas, Texas, 21-24 September, 1980.
Liu, B., Liang, Y., Ito, T. Numerical study on micro-cracks and permeability changes linked to clay swelling after fracturing in shale rock. Journal of Petroleum Science and Engineering, 2022, 217: 110847.
Liu, K. Upper cretaceous sequence stratigraphy, sea-level fluctuations, and oceanic anoxic events 2 and 3, northeastern Gulf of Mexico. Stratigraphy, 2005, 2(2): 147-166.
Lu, J., Milliken, K., Reed, R. M., et al. Diagenesis and sealing capacity of the middle Tuscaloosa mudstone at the Cranfield carbon dioxide injection site, Mississippi, USA. Environmental Geosciences, 2011, 18(1): 35-53.
Lu, J., Ruppel, S. C., Rowe, H. D. Organic matter pores and oil generation in the Tuscaloosa marine shale. AAPG Bulletin, 2015, 99(2): 333-357.
Makhanov, K., Dehghanpour, H., Kuru, E. Measuring liquid uptake of organic shales: A workflow to estimate water loss during shut-in periods. Paper SPE 167157 Presented at the SPE Unconventional Resources Conference Canada, Alberta, Canada, 5-7 November, 2013.
Nippes, V. Production behavior and decline curve analysis of Tuscaloosa Marine Shale wells in Wilkinson and Amite Counties, Mississippi. Lafayette, University of Louisiana at Lafayette, 2019.
Pittman, E. D. Relationship of porosity and permeability to various parameters derived from mercury injection-capillary pressure curves for sandstone. AAPG Bulletin, 1992, 76(2): 191-198.
Shaibu, R., Guo, B. The dilemma of soaking a hydraulically fractured horizontal shale well prior to flowback-a decade literature review. Journal of Natural Gas Science and Engineering, 2021, 94: 104084.
Shen, Y., Ge, H., Li, C., et al. Water imbibition of shale and its potential influence on shale gas recovery-a comparative study of marine and continental shale formations. Journal of Natural Gas Science and Engineering, 2016, 35: 1121-1128.
Wang, Q., Zhao, J., Hu, Y., et al. Shut-in time optimization after fracturing in shale oil reservoirs. Petroleum Exploration and Development, 2022, 49(3): 671-683.
Yaich, E., Williams, S., Bowser, A., et al. A case study: The impact of soaking on well performance in the Marcellus. Paper URTEC 2154766 Presented at the SPE/AAPG/SEG Unconventional Resources Technology Conference, San Antonio, Texas, 20-22 July, 2015.
Yan, Q., Lemanski, C., Karpyn, Z. T., et al. Experimental investigation of shale gas production impairment due to fracturing fluid migration during shut-in time. Journal of Natural Gas Science and Engineering, 2015, 24: 99-105.
Yang, X., Guo, B. Statistical analyses of reservoir and fracturing parameters for a multifractured shale oil reservoir in Mississippi. Energy Science & Engineering, 2020, 8(3): 616-626.
Refbacks
- There are currently no refbacks.
Copyright (c) 2024 The Author(s)
This work is licensed under a Creative Commons Attribution-NonCommercial-NoDerivatives 4.0 International License.