Stacked Pay Pad Development in the Midland Basin
- Farhan Alimahomed (Schlumberger) | Raj Malpani (Schlumberger) | Rohann Jose (Schlumberger) | Elia Haddad (Schlumberger) | Edgar V. Arteaga (Schlumberger) | Lance Smith (Schlumberger) | Shrutesh Lati (Schlumberger)
- Document ID
- Society of Petroleum Engineers
- SPE Liquids-Rich Basins Conference - North America, 13-14 September, Midland, Texas, USA
- Publication Date
- Document Type
- Conference Paper
- 2017. Society of Petroleum Engineers
- 7 Management and Information, 7.6 Information Management and Systems, 5.2 Reservoir Fluid Dynamics, 5.6.1 Open hole/cased hole log analysis, 5 Reservoir Desciption & Dynamics, 1.6.6 Directional Drilling, 1.6 Drilling Operations, 2.4 Hydraulic Fracturing, 7.6.4 Data Mining, 2.1 Completion Selection and Design, 5.5.8 History Matching, 5.6 Formation Evaluation & Management, 2.1 Completion Selection and Design, 0.2 Wellbore Design, 5.5 Reservoir Simulation, 3 Production and Well Operations, 2 Well completion, 1.2.3 Rock properties
- Unconventional, Midland Basin, Pad, Stacked, Horizontal
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The Midland Basin has seen an unprecedented boom in pad drilling over the last year, largely due to the stacked pay, comprising of the Spraberry and the Wolfcamp formations. Operators are targeting up to four different reservoirs in one section, using a wine-rack pattern, which is the future of pad drilling. The workflows discussed in this paper will help us in understanding the growth of the hydraulic fractures and their production interference with the offset wells. These integrated workflows are centered on building a calibrated 3D model, to perform predictive modeling on various combinations of stacked laterals and determine the optimum spacing, both vertically and laterally.
Technology integration plays a significant role in identifying the key drivers of production. Our workflows involve building a geomodel using high tier pilot well logs and utilizing an unconventional fracture model (UFM) to simulate hydraulic fractures to understand the overall fracture footprint. The fractures are then gridded in an unstructured manner and fed to a numerical reservoir simulator to perform production history matching. This is the most crucial step in the process because this calibrated model is then usedfor predictive modeling of the various combinations of lateral spacing and stacking.
Pilot well logs show varying degrees of high stress barriers that exist across the basin, and knowing the stress regime local to a field or section is important in determining the optimum landing locations and completion designs. Typical pump schedules for the zones of interest were selected based on current industry practices. Fully 3D planar fracture simulations performed on the pilot well resulted in 18 potential landing locations spanning the Upper Spraberry to the Lower Cline, based on fracture heights and theinterference between the zones. Out of the 18 targets, fivewere selected based on production potential. UFM simulations along the lateral show different fracture geometries in different reservoirs due to varying rock properties and natural fracture orientations. The production history matching was performed using a P50 type curve generated using public data for eachreservoir in the county, and using known reservoir fluid properties.
The modeling approach discussed in this paper can be applied to any data set within the basin to determine the optimum landing location, which could vary depending on changing reservoir properties. It acts as an alternative approach to field testing varying spacing combinations, which could be both, expensive and time consuming.
|File Size||3 MB||Number of Pages||15|
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