The Mancos-Niobrara formation in western Colorado is estimated by the USGS to contain 66 trillion cubic feet of natural gas. Successfully developing this asset depends on understanding the geology, geomechanics, the impact of fracture length and height, conductivity, fracture spacing, and well spacing on estimated ultimate recovery. The Mancos-Niobrara has tremendous resource potential and is in the early stages of development in the study area. This paper discusses the development and application of a detailed numerical reservoir model to guide best practice development. Six wells drilled from two multi-well pads and hydraulically fractured to produce natural gas are the subject of this paper. This study provides a comprehensive evaluation and integrated approach to help optimize field development in this new emerging play.
The reservoir model includes six wells on two pads. The reservoir was characterized using geochemistry, triple-combo logs, dipole-sonic logs, and formation images. Completion geometry and efficiency were evaluated by collecting data including micro-seismic fracture mapping, micro-deformation, mini-fracturing tests, and production logs. Different designs or treatment schedules were utilized during completion operations to provide additional information on the formation sensitivity to differing completion parameters. The numerical reservoir modeling performed in this study gives deference to the rich data collected. The model was used to estimate effective fracture lengths and heights, evaluate well communications, predict individual well performance, and identify areas for economic optimization. Created fracture half-lengths were estimated to be 900-1,000 ft. This result shows excellent agreement between history matching the hydraulic fracture treatment, micro-seismic monitoring, and production results. The reservoir model confirms direct hydraulic connections, modeled as a few high-conductivity pathways (‘pipelines’), crossing multiple wells that could result from the repeated enhancement of the same natural fracture network during different treatment stages.
Production results show large performance differences among the wells despite the similarity in completion designs which is attributed to well interference and shared production. Therefore, it would be advantageous in future development―utilizing essentially the same completion technique, double well spacing to 2,700 ft., while still maintaining 75%-80% gas recovery factors over 40 years, and drilling half the number of wells. Production logging indicated that only 30% of perforated clusters were producing a significant amount of gas. The simulation sensitivity shows that significant gas production boost was possible, especially in the first five years, if cluster efficiency was increased. Fracture conductivity was found to be of secondary importance for short and long-term gas recoveries due to the low system permeabilities. Accordingly, the flexibility in diversion techniques and varying proppant size to increase cluster efficiency should be tested. The reservoir modeling also shows that only a portion of the gross formation thickness may be effectively produced implying that the effective fracture height may be less than 750 ft. measured by micro-deformation. This leads to a future opportunity of targeting the more liquids-rich upper Niobrara zones in addition to the lower gas-producing interval.