Proppant Optimization for Foam Fracturing in Shale and Tight Reservoirs
- Ming Gu (West Virginia University) | Ming Fan (Virginia Tech) | Cheng Chen (Virginia Tech)
- Document ID
- Society of Petroleum Engineers
- SPE Unconventional Resources Conference, 15-16 February, Calgary, Alberta, Canada
- Publication Date
- Document Type
- Conference Paper
- 2017. Society of Petroleum Engineers
- 2 Well completion, 5.5 Reservoir Simulation, 2.4 Hydraulic Fracturing, 1.8 Formation Damage, 4 Facilities Design, Construction and Operation, 3 Production and Well Operations, 4.1.2 Separation and Treating, 3 Production and Well Operations, 5 Reservoir Desciption & Dynamics, 5.8 Unconventional and Complex Reservoirs, 4.1 Processing Systems and Design, 2.5.2 Fracturing Materials (Fluids, Proppant)
- conductivity modeling, fracture modeling, production optimization, sand proppant, foam fracturing
- 2 in the last 30 days
- 345 since 2007
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Slickwater frac is widely used for stimulating the productivity of unconventional shale and tight reservoirs nowadays. Slickwater produces long skinny fractures, but only the near wellbore region is propped due to fast settling of sand. Adding gel can slow down sand settling, but gel damages the fracture surface and proppant pack. Other issues include large water consumption, water damage, and high water disposal cost. Recently, a non-damaging, less water-intensive fracturing fluid system with improved sand placement efficiency, known as polymer-free foam (PFF), is developed by Gu (2013). The current objective is to study the impacts of sand pumping designs on PFF fracturing efficiency by conducting numerical modeling. In the first step, discrete element method (DEM) and lattice Boltzmann method (LBM) are employed to simulate proppant particle compression, rearrangement, and conductivity for different mesh sizes and areal concentrations under different fracture closure stresses. Next, the conductivity results are input in an in-house fracture propagation model to simulate the fracture conductivity distribution after foam fracturing. After that, the fracture conductivity distribution is input in a reservoir production model to predict the productivity. A parametric study is conducted to understand the impacts of sand mesh size and pumping load on foam frac. With the study, the optimal sand size and concentration are determined for the new fracturing fluid system in shale and tight reservoirs. Our results show, for 140 nD shale gas reservoirs, pumping mesh 100 sand at a volume ratio of 0.15 v/v, 0.125 v/v, and 0.1 v/v are optimal sand pumping designs for PFF treatments with foam quality of 60, 70, and 80%, respectively. If the reservoir permeability is ten times larger, the optimal sand pumping designs for 60, 70, and 80% quality PFF treatments are mesh 30/50 at 0.15 v/v, mesh 100 at 0.125 v/v, and mesh 100 at 0.125 v/v, respectively. With the optimization of sand pumping design, well production can be increased by 110% for low permeability shale, or by 70-100% for high permeability tight or naturally-fractured shale formations. This paper develops a time-efficient workflow to optimize sand pumping strategy for the new PFF fracturing system. The methodology includes coupled DEM/LBM modeling of proppant conductivity, fracture modeling, and reservoir production simulation. The PFF fracturing system with optimized sand mesh size and load can provide enhanced productivity with less water consumption, less gel and water damage, and lower water disposal cost.
|File Size||1 MB||Number of Pages||13|
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