Water Saturation in Unconventionals: The Real Story
- Timothy Dash (W.D. Von Gonten & Co. Petroleum Engineering) | Safdar Ali (W.D. Von Gonten & Co. Petroleum Engineering) | Mansoor Ali (W.D. Von Gonten Laboratories) | Brian Chin (W.D. Von Gonten Laboratories) | Ashish Mathur (W.D. Von Gonten Laboratories) | Ricardo Hartanto (Consultants) | Vivek Ravi (Consultants)
- Document ID
- Society of Petrophysicists and Well-Log Analysts
- SPWLA 61st Annual Logging Symposium - Online, 24 June - 29 July, Virtual Online Webinar
- Publication Date
- Document Type
- Conference Paper
- 2020. held jointly by the Society of Petrophysicists and Well Log Analysts (SPWLA) and the submitting authors
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Understanding the volumetric concentrations of hydrocarbon and water in a producing reservoir is a critical component of predicting well performance, designing well placement and field development planning. Core testing procedures and petrophysical models in unconventional shale reservoirs have always faced the challenges of establishing representative in-situ water and hydrocarbon saturations. When using existing techniques of core calibrated petrophysics, actual well production often varies significantly from expectations. These variations may include scenarios such as lower overall oil production or strong oil production that is accompanied by large volumes of produced water. This has a serious impact on the development of major U.S. unconventional plays such as the Wolfcamp, Spraberry Shale, Austin Chalk, Eagleford, among many others.
Core taken from these formations is the key to better understanding what fluids are present and in what quantities. It is well agreed upon that changes in pressure and temperature as rock is taken from downhole, handled and transported to a laboratory facility affect the contents of the pore system. This generally results in a varying amount of void space that is measured in the rock at the lab. Standard practice calls for treating this void space as previously occupied by oil that has volatized during coring operations, transport, and core testing. Therefore, estimates of hydrocarbon filled porosity are made using the volume of oil extracted from the rock during testing (whether thermally or via solvents) combined with the volume of void space measured. Water Saturation is assigned a value based on the actual water measured from the rock during the extraction process.
However, fluid phase behavior in nano-pore systems is not very well understood. Pore wettability and permeability are also important factors that may control what fluids are lost from the system. Given these uncertainties, the assumption that void space is associated with volatized hydrocarbon does not hold true. Through updated procedures and use of new equipment, it has been shown that a significant portion of this void filled porosity is occupied by formation water at reservoir conditions. The discussion below will show several experiments validating this idea including: comparisons between preserved and non-preserved core samples, re-testing old core to measure fluid changes with time, nuclear magnetic resonance (NMR) scans, flow-through and fluid imbibition studies among others. Where available, NMR T1-T2 logs will be used as a downhole water saturation reference. Additionally, log interpretations calibrated to this new water saturation will be shown and compared to well performance.
|File Size||1 MB||Number of Pages||11|