Application of the New Sonic-Based Saturation Model to Conventional and Unconventional Oil Reservoirs
Downtown Houston
Speaker:
Seminar Date: Apr 24 2025
Registration Opens: Mar 10 2025 - Apr 24 2025
Time: 12:00 PM - 01:00 PM (US CDT)
Admission/Registration Link: https://register.gotowebinar.com/register/5239402050653457496
Donation Link: None
Meeting/Webinar Link: None
Contact: Artur Posenato Garcia (VP Downtown, SPWLA Houston Chapter)
Corresponding: vpdowntown@spwla-houston.org
Fees: FREE
ABSTRACT:
It is well established in rock physics that when the fluid filling the pore spaces of a reservoir is primarily gas or light oil there is a significant change in the bulk modulus but little to no changes in the shear modulus when compared to fully brine-saturated reservoirs. This in turn leads to a lower velocity ratio in gas or light oil reservoirs. This concept underlies and has been extensively used in the fluid identification of conventional siliciclastic reservoirs in seismic interpretation. Yet not so much in the use of higher-resolution sonic logs. Here we ask the question, can we use sonic logs to not just identify but quantify hydrocarbon saturation in gas reservoirs? Using sonic logs, can we accurately estimate water saturation with uncertainties that are similar to those obtainable from conventional saturation models? If possible, this would have significant implications in the evaluation of shaly sand reservoirs as well as low resistivity low contrast reservoirs, where conventional saturation models may not be as effective. Given P-wave and S-wave velocities computed from measured compressional and shear sonic logs, a new empirically derived saturation model for estimating water saturation is presented. One that does not require formation resistivity or brine salinity. The new model is based on the lower bulk modulus or velocity ratio observed in gas reservoirs. Assuming the reservoir is fully brine saturated, the deviation of the measured P-wave and S-wave velocities from the fully brine saturated velocities is used to invert for water saturation. The new model is shown to be consistent with theoretical rock physics models. We have applied the new model to compressional and shear sonic well log data acquired in several reservoirs. The reservoirs range from an organic gas shale reservoir to a gas sand reservoir offshore the Gulf of Mexico. In one of the organic shale examples, the Haynesville shale, average water saturation from the new model was 33% compared to 34% from the conventional saturation model that has been calibrated to tight rock core analysis. In the Gulf of Mexico gas sand example, the model yields 24% average water saturation compared to 21% average water saturation from core calibrated Archie saturation model. In a low resistivity low contrast shaly sand reservoir where conventional saturation models indicated the reservoir is wet, the new model yields results that are consistent with gas production from the reservoir. We also present the results of the application of the new model to a gas condensate reservoir in the North Slope of Alaska and an oil reservoir offshore the Gulf of Mexico.
BIOGRAPHY:
Sheyore John Omovie is a Petrophysical Consultant at Goshey Energy Services LLC with over 2 decades of experience working in several basins in the US and internationally. He has worked for Apache Corporation, Oxy, EOG, and Baker Hughes. He received a PhD in Geophysics from the University of Houston. His research focuses on rock physics, and rock mechanical properties. He is also a licensed professional geoscientist in the state of Texas, USA.