Investigating Optimized Well Placement in San Andres Tight Oil Dolomite Reservoir by Integrated Reservoir Modeling Approach
- Junjie Yang (Baker Hughes, a GE Company) | Pierre Karam (Baker Hughes, a GE Company) | Kristian Cozyris (Baker Hughes, a GE Company) | Crystal Hustak (Baker Hughes, a GE Company) | James Doherty (Riley Exploration – Permian, LLC) | Carmen Allen (Riley Exploration – Permian, LLC)
- Document ID
- Society of Petroleum Engineers
- SPE Oklahoma City Oil and Gas Symposium, 9-10 April, Oklahoma City, Oklahoma, USA
- Publication Date
- Document Type
- Conference Paper
- 2019. Society of Petroleum Engineers
- 3.3.6 Integrated Modeling, 5.5 Reservoir Simulation, 2 Well completion, 1.6.9 Coring, Fishing, 3 Production and Well Operations, 5.5.2 Core Analysis, 4.1.2 Separation and Treating, 2.1 Completion Selection and Design, 5.5.8 History Matching, 4 Facilities Design, Construction and Operation, 3 Production and Well Operations, 0.2 Wellbore Design, 5.1.5 Geologic Modeling, 5 Reservoir Desciption & Dynamics, 5.8.7 Carbonate Reservoir, 3.3 Well & Reservoir Surveillance and Monitoring, 2.1 Completion Selection and Design, 5.6 Formation Evaluation & Management, 1.6.6 Directional Drilling, 4.1 Processing Systems and Design, 2.5.5 Re-fracturing
- Simulation, optimization, unconventional
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As a well-known tight oil dolomite reservoir in Texas, San Andres formation has attracted broad attention about horizontal drilling and development strategy. To optimize the oil recovery and asset’s economics, the aim of the study was to use an integrated approach to understand reservoir heterogeneity and performance, determine optimal landing zone and its impact on production, understand fracture geometry using different pumping schedules, and the optimal cluster spacing. In addition, the potential benefit of a refrac and infill drilling program was also investigated.
To tackle the optimization problem, an integrated reservoir modeling workflow was developed. Starting with a 1-D geomechanical model which captures the in situ stress profile and rock mechanics, hydraulic fracture modeling was developed to history match the treatment process, and therefore a comprehensive fracture geometry can be estimated. In the interim, a geological model with populated reservoir properties was established based on the offset data including petrophysical logs, imaging logs and cores. After calibration, the dynamic reservoir model was built to test multiple sensitivity runs for an optimized field development strategy.
Geological modeling separated the field into two models to study the variation of properties on the east and west side. The east section shows a higher porosity and lower saturations. Those water saturations increase below the main pay zone indicating a potential water source. In addition, special core analysis shows a strong oil-wet nature of the reservoir rock. In the east section, sensitivity runs included infill development and variations in landing depth. It is noted that the production is not sensitive to landing zone because fracture geometry is primarily controlled by vertical stress profile. In the west section, sensitivity runs included refrac, infill drilling, and a greenfield development plan with variations on well spacing and completion design. The observation shows tighter well spacing or cluster spacing accelerates the oil production in early time, while yielding similar long term oil recovery and shows a combination of refrac and infill drilling yields a 21% incremental oil production beyond the base case.
This study provides valuable information about the workflow to develop tight oil plays by describing a detailed case study. The result also sheds light on the optimized field development strategy for analogous fields.
|File Size||3 MB||Number of Pages||13|