The Mesaverde formation is a low permeability gas sandstone reservoir and a primary completion target in the San Juan Basin of northwest New Mexico and southwest Colorado. In over 50 years of Mesaverde development activity, varying completion and stimulation techniques have been tried in an effort to find the optimum method for enhancing long-term production. Initially, production and economic analysis indicated that high rate slickwater jobs using 20/40 mesh sand (specific gravity = 2.65) proved most effective. One attribute of the slick water approach is that the relatively heavy fracturing sand falls rapidly through the low-viscosity water and forms a bank of proppant over a very limited percentage of the total fracture area created with the hydraulic fluid (water.)As the field matured, reservoir pressure depleted and drilling cost escalated, the need arose for a different stimulation approach creating more extensive area open for fracture flow and reservoir drainage enhancement. To address this need, a lightweight proppant (specific gravity = 1.25) was substituted in lieu of fracturing sand with the idea of placing a partial mono-layer of proppant across a very large percentage of the total fracture area. This paper is a case study of six recent offset Mesaverde completions comparing the productivity of wells stimulated with all 20/40 mesh sand, all lightweight proppant and a hybrid approach utilizing a stage of lightweight proppant followed by a stage of 20/40 mesh sand. Post-fracture hourly flow rates and wellhead pressures were analyzed in all cases to access effectiveness. Wells treated with all lightweight proppant were found to have the most sustained well productivity and stimulation effectiveness.
The Mesaverde grouping, the largest low permeability producer of gas in the San Juan Basin, was deposited along the Cretaceous Western Interior Seaway during the late Cretaceous period. The Mesaverde group includes the Cliff House, the Menefee, and the Point Lookout sandstone. Gas-in-place estimates vary but have been estimated as high as 38 trillion cubic feet of gas. It is a naturally fractured reservoir that has a total thickness of approximately 900 feet. The average depth to the top of formation is 5400 feet. Typical frac gradients are 0.43 - 0.45 psi per foot. It is a very mature reservoir with initial production dating back to the late 1920's.
The wells being drilled are on the outer edge of the basin. The average Estimated Ultimate Recovery (EUR) is the range of 0.5 - 1.5 Bcf. This makes the need to increase the wells recoverable reserves of utmost importance. A completion system has been developed to address this reservoir issue.