Unlocking Additional Barrels From a Mature Conventional Oil Field Through Unconventional Technologies: A Case Study on Rangely Oil Field, Colorado

Abstract

Abstract Demonstrating the viability of multistage hydraulic fractured horizontal wells to unlock otherwise trapped resources is presented through a case study on Rangely. A combination of high-fidelity reservoir models was employed for accurate forecasts and evaluation of hydraulically fractured horizontal wells to improve resources in this mature conventional oil field with ongoing pressure support and tertiary recovery operations. The modeling techniques used in this method can be extended to other mature oil fields to unlock bypassed oil setting a precedent to re-evaluate mature oil fields with the new unconventional completion technologies. The Rangely Weber Sand Unit is an Eolian sandstone depositional system consisting of 2 billion bbls of oil in place. The Weber Formation is Pennsylvanian to Permian in age, and typically consists of fine-grained and cross bedded calcareous sandstones. Structurally oil is trapped in an anticline with varying dip angles on the flanks. The oil production from this reservoir was managed through primary depletion for the first two decades of production followed by secondary recovery via water flood and concluding through water alternating CO2 injection (WAG) over the last three decades. Due to the heterogeneity in depositional environment, the recovery factors have been low in the eastern end of the field. The east end of the field has relatively lower permeability and lower porosity compared to the rest of the field. A modeling workflow is presented to assist with evaluation and optimization of hydraulically fractured horizontal infill wells to recover bypassed oil in the eastern end of the Rangely field. A full fidelity static model was built based on dense, high quality well control data. A sector model was history matched, and then used to update pressure, saturations, and stress distribution to present day. The history matched model was subsequently used to evaluate horizontal well performance and hydraulic fracturing completion options to overcome these heterogeneities and improve recovery from a lower quality reservoir. Completions optimization opportunities were focused on fracture geometry, incremental Estimated Ultimate Recovery (EUR), and economics. Sensitivity studies demonstrated that an optimal balance of cost and recovery is found at the low end of fracture volumes and wider perforation cluster spacing. Forecasting runs show incremental economic recovery which otherwise could not have been recovered through ongoing WAG operations.