The Effects of Downspacing on Recovery Factor Using Type Curve Analysis and Accounting for Adsorbed Hydrocarbon in a Multi-Phase Unconventional Reservoir: Eagle Ford Case Study
The Eagle Ford Shale of South Texas is one of the most prolific unconventional oil and gas plays in the world. Current development has operators maximizing field recoveries through multi-disciplinary efforts in determining well spacing, particularly through use of staggered and/or stacked downspacing to access various geologic horizons within the reservoir (Grossi et al., 2015, Lindner et al., 2015). Determining the ultimate recovery factor of an unconventional resource is not a trivial task. It requires knowledge of total in-place hydrocarbons, the extent of the drainage volume, and the ultimate well recoveries – all historically difficult to quantify in these reservoirs (Baihly et al., 2015, Gherabati et al., 2016). This study presents a systematic approach in quantifying the key factors that determine ultimate field recoveries. In this paper a general multi-segment type curve methodology for multi-phase unconventional reservoirs is presented. General flow regime identification is discussed. The determined b-value of 1.2 fits the production data, and is supported by numerical modeling. However, in downspaced wells individual well performance dictates a b-value of 1.1. In addition, the timing to switch to exponential segment is explored using numerical modeling long-term production profile. In addition, adsorbed gas has been shown to be a significant component of gas-in-place (GIP) in shale gas systems (Ambrose et. al., 2010). The same considerations must be made for shale oil. A novel methodology as described in Wang et al. (2015) was used to calculate the adsorbed and free components for total hydrocarbons in-place in the Eagle Ford on a 131-well, core-calibrated wireline log dataset. Adsorbed gas makes up approximately 33% of the total GIP while adsorbed oil is about 11% of the total OIP. Comparisons to standard volumetric methods (assuming a constant hydrocarbon density) showed an average 11% increase in total GIP and increased OIP by 4%. Reservoir engineering techniques justify decline curve parameters (b-value) that vary depending both on well spacing and hydrocarbon absorption. We found recovery factors for the Eagle Ford shale can be upwards of 50% using multi-zone development, compared to less than 15% in historic single-zone development areas.
AAPG Datapages/Search and Discovery Article #90291 ©2017 AAPG Annual Convention and Exhibition, Houston, Texas, April 2-5, 2017