Well-spacing Study to Develop Stacked Tight Oil Pay in Midland Basin
- A.S. Cullick (Linn Energy) | M. Carrillo (LaRoche Petroleum Consultants) | C. Clayton (Consulting Geologist) | I. Ceyhan (Blade Energy Partners)
- Document ID
- Society of Petroleum Engineers
- SPE Unconventional Resources Conference, 1-3 April, The Woodlands, Texas, USA
- Publication Date
- Document Type
- Conference Paper
- 2014. Society of Petroleum Engineers
- 1.2.2 Geomechanics, 5.1 Reservoir Characterisation, 5.3.4 Reduction of Residual Oil Saturation, 4.3.4 Scale, 1.6.9 Coring, Fishing, 4.1.5 Processing Equipment, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 5.1.9 Four-Dimensional and Four-Component Seismic, 2.5.4 Multistage Fracturing, 5.8.6 Naturally Fractured Reservoir, 3 Production and Well Operations, 5.6.11 Reservoir monitoring with permanent sensors, 5.1.3 Sedimentology, 5.5 Reservoir Simulation, 5.7.5 Economic Evaluations, 1.2.3 Rock properties, 5.8.2 Shale Gas, 5.5.8 History Matching, 5.1.5 Geologic Modeling, 3.3.1 Production Logging, 5.2.1 Phase Behavior and PVT Measurements, 5.1.7 Seismic Processing and Interpretation, 5.5.3 Scaling Methods
- simulation, tight oil, well spacing, Midland Basin
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Tight formations in the Midland Basin under active development include Clearfork, Wolfcamp, Spraberry, Strawn, Cline, Atoka, and Mississipian formations, which are usually found between 6000 feet and 11,500 feet TVD. Development is typically with vertical wells, which are stimulated with multiple hydraulic fractures targeting the best expected pay intervals for commingled production. A significant challenge for operators is determining the optimum well locations and spacing for efficient reserve development. Operators use various field data and analytics to determine well spacing, although limited data, for example only early in-life production data, and lack of zonal production or pressure data pose difficulties to making good decisions. In this situation, numerical models can yield insights about drainage patterns.
This paper reports a case study using a geologic model and a reservoir simulation model to evaluate reducing well spacing to increase gross recovered oil. A three-dimensional geologic model was constructed for a 14-section area in the Midland Basin using detailed log evaluations for net pay intervals, core calibrations and production test data. An extensive core-log statistical study yielded calibrated rock types at the wells. Reservoir and geomechanical properties were then spatially distributed using geostatistical techniques subject to three-dimensional seismic constraints, to yield pore volume, saturation, and brittleness. A reservoir simulation model was then generated from the geologic model for a 223-acre (3600 feet x 2700 feet) sector of interest.
The sector model was history-matched to early production data and historical type curves. Each well had 10-12 fracture stages, which were explicitly modeled using parameters derived from post-execution analysis of fracture job data. Pressure data were obtained from submersible pump sensors, where available, or estimated from wellbore fluid level surveys. Once history-matched, the simulation model was run on prediction mode for 40-acre and 20-acre well spacing. Incremental production and economic comparisons resulting from in-fill well spacing is presented.
The study provides a technical workflow for analyzing potential to decrease well spacing. It also provides insights into the formation rock types to be able to better evaluate formation potential.
|File Size||2 MB||Number of Pages||14|