As activity increases in the Permian Basin and multiple billion-dollar acquisitions at upwards of &50,000/acre continue, there is a strong incentive for E&P operators to optimize the development in their existing acreage. Unfortunately, maximizing oil production typically results in significant amounts of produced water. Water cuts for individual Permian wells commonly range from 50 to 90% of total liquid production, thus the ability to predict water to oil ratio (WOR) of the produced fluids has a major importance for development planning (Scanlon et al., 2017).
Petrophysicists are responsible for fluid saturation modeling, which provides the basis for predicting WOR. Core data acquisition and analysis are critical for developing a quantitative petrophysical model. However, accurately measuring saturations of cores taken from unconventional reservoirs continues to pose significant challenges originating from uncertainties in the acquired data, assumptions used to interpret these data and more broadly, due to increased relative uncertainty associated with tight, low-porosity formations.
For example, the crushing of the core samples, which is required for efficient fluid extraction in tight rocks, causes systematic fluid losses which are not typically quantified. Instead, all as-received air-filled porosity is commonly assumed to represent hydrocarbons that have escaped during coring due to gas expansion. Additionally, fluid extraction from commercially available retorting systems can have widely variable fluid collection efficiency (<100%) resulting in significant inconsistencies between the weight of the collected fluids and sample weight loss during retorting experiments. The Dean-Stark technique removes not only fluids (water and oil) but an unknown volume of the extractable organic matter, and it only allows for direct quantification of the volume of extracted water. The reconciliation of fluid volume as well as fluid and sample weight data delivered by either of the two techniques (i.e., retorting or Dean-Stark) requires numerous assumptions about pore fluid properties which are typically not verified through direct measurements. We demonstrate that such assumptions can lead to up to 50% uncertainty in water saturation estimates.
To address such critical uncertainties, a new core analysis workflow using improved core characterization and fluid extraction techniques was developed. To address fluid loss during crushing, this workflow employs advanced NMR measurements performed on both as-received and crushed samples to quantify fluid losses. Also, this approach uses retorting techniques with close to 100% fluid collection efficiency specially developed for core sample characterization. The workflow is further optimized to avoid fluid loss during sample handling and includes repeated grain density and geochemical measurements at different stages. As a result, the new workflow addresses uncertainties in acquired data and better informs the assumptions for interpreting the measured data into the desired petrophysical properties (e.g. total porosity, water saturation). The workflow is demonstrated for a set of Wolfcamp samples.