Effects of Confinement on Compositional Simulation in Shale Reservoirs with Thermodynamic Properties Upscaling from Pore- to Reservoir-Scale
- Authors
- Xiaona Cui (Texas A&M University and Northeast Petroleum University) | Kaoping Song (China University of Petroleum - Beijing) | Erlong Yang (Northeast Petroleum University) | Tianying Jin (Texas A&M University) | Jingwei Huang (Texas A&M University) | John Killough (Texas A&M University) | Chi Dong (Northeast Petroleum University)
- DOI
- https://doi.org/10.2118/196092-MS
- Document ID
- SPE-196092-MS
- Publisher
- Society of Petroleum Engineers
- Source
- SPE Annual Technical Conference and Exhibition, 30 September - 2 October, Calgary, Alberta, Canada
- Publication Date
- 2019
- Document Type
- Conference Paper
- Language
- English
- ISBN
- 978-1-61399-663-8
- Copyright
- 2019. Society of Petroleum Engineers
- Keywords
- upscaling, compositional simulation, phase behavior, shale reservoir
- Downloads
- 3 in the last 30 days
- 273 since 2007
- Show more detail
- View rights & permissions
| SPE Member Price: | USD 5.00 |
| SPE Non-Member Price: | USD 28.00 |
The phase behavior shifts of hydrocarbons confined in nanopores have been extensively verified with experiments and molecular dynamics simulations. However, the impact of confinement on large-scale reservoir production is not fully understood. This work is to put forward a valid method to upscale the pore-scale fluid thermodynamic properties to the reservoir-scale and then incorporate it into our in-house compositional simulator to examine the effect of confinement on shale reservoir production.
Firstly, a pore-scale fluid phase behavior model is developed in terms of the pore type and pore size distribution (PSD) in the organic-rich shale reservoir using our modified Peng-Robinson equation of state (PR-C EOS) which is dependent on the size-ratio of fluid molecule dynamic diameter and the pore diameter. And the fluid composition distribution and PVT relation of fluids in each pore can be determined as the thermodynamic equilibria are achieved in the whole system. Results show that the initial fluid composition distribution is not uniform for different pore types and pore sizes. Due to the effect of confinement, heavier components are retained in the macropore, and lighter components are more liable to accumulate in the confined nanopores. Then an upscaled equation of state is put forward to model the fluid phase behavior at the reservoir-scale based on our modified PR-C EOS using a pore volume-weighted average method. This upscaled EOS is validated with the pore-scale fluid phase behavior simulation results and can be used for compositional simulation. Finally, two different reservoir fluids from the Eagle Ford organic-rich shale reservoir are simulated using our in-house compositional simulator to investigate the effect of confinement on production. In addition to the critical property shift which can be described by our upscaled PR-C EOS, capillary pressure is also taken into account into the compositional simulation. Results show that the capillary pressure has different effects on production in terms of the fluid type, leading to a lower producing Gas/Oil ratio (GOR) for black oil and a higher GOR for gas condensate. Critical property shift has a consistent effect on both the black oil and gas condensate, resulting in a lower GOR. It should be noted that the effect of capillary pressure on production is suppressed for both fluids with the shifted critical property.
| File Size | 2 MB | Number of Pages | 19 |
Alharthy, N. S., Nguyen, T., Teklu, T., Kazemi, H., & Graves, R, 2013. Multiphase compositional modeling in small-scale pores of unconventional shale reservoirs. SPE 166306, paper to be presented at SPE Annual Technical Conference and Exhibition held in New Orleans, Louisiana, USA. September 30-October 2.
Bao, A., Hazlett, R. D., & Babu, D. K., 2017. A Discrete, Arbitrarily Oriented 3D Plane-Source Analytical Solution to the Diffusivity Equation for Modeling Reservoir Fluid Flow. Society of Petroleum Engineers. doi:10.2118/185180-PA.
Dong, X., Liu, H., Hou, J., Chen, Z., Wu, K., & Zhan, J, 2016. Phase Behavior of Multicomponent Hydrocarbons in Organic Nanopores under the Effects of Capillary Pressure and Adsorption Film. SPE-180237-MS, paper to be presented at the SPE Low Perm Symposium held in Denver, Colorado, USA. May 5-6.
He, Y., Cheng, S., Li, S., Huang, Y., Qin, J., Hu, L., and Yu, H. 2017. A semianalytical methodology to diagnose the locations of underperforming hydraulic fractures through pressure-transient analysis in tight gas reservoir. SPE Journal, 22 (03), 924–939. https://doi.org/10.2118/185166-PA.
Khoshghadam, M., Khanal, A., & Lee, W. J, 2015. Numerical study of impact of nano-pores on gas-oil ratio and production mechanisms in liquid-rich shale oil reservoirs. In Unconventional Resources Technology Conference, San Antonio, Texas, 20-22 July (pp. 1799–1817). Society of Exploration Geophysicists, American Association of Petroleum Geologists, Society of Petroleum Engineers.
McLean, R., Miller, C., Guzman, B., & Walls, J, 2017. Quantifying Organic Porosity and Predicting Estimated Ultimate Recovery (EUR) in the Eagle Ford Formation. In Unconventional Resources Technology Conference, Austin, Texas, 24-26 July (pp. 92–107). Society of Exploration Geophysicists, American Association of Petroleum Geologists, Society of Petroleum Engineers.
Xiong, X., Devegowda, D., Civan, F., Sigal, R. F., & Jamili, A, 2013. Compositional Modeling of Liquid-Rich Shales Considering Adsorption, Non-Darcy Flow Effects and Pore Proximity Effects on Phase Behavior. SPE 168836, paper to be presented at Unconventional Resources Technology Conference held in Denver, Colorado, USA. August 12-14.
