Implications Of Core / Log Porosity Re-Calibration To Our Reserves With Case From Clastic Reservoirs

Abstract

The need to identify net pay potential arises in a number of reservoir evaluation initiatif. A procedure commonly used to produce a net pay predictor involves the use of the porosity vs. permeability cross plot and a least squareregression line to identify the net pay cut off porosity. Net pay definition varies and many experts have their owned views. It is not necessary pay cutoff derived from porosity permeability cross plot. If the perm has influenced the flowability, then the poro-perm will be used to derive the associated porosity cut off. Statistical issues related to the accuracy of net pay cut offs based on porosity are addressed on this poster presentation. The exercise of identifying net pay and estimating the net-to-gross ratio require two different porosity cut off values to be defined to keep errors as low as possible. Porosity values determined by core analysis are generally accepted as superior to log estimates. The presence of shale (clay) in the pay zone complicates log interpretation. Routine measurement of properly preserve cores cut give accurate porosity and water saturation (Sw) values in hydrocarbon reservoirs. Again, core Sw is a function of core cleaning and also drilling fluid invasion, of course, one may suggest doping the mud to correct for the invasion in core. HPV evaluations from the core and total and effective porosity systems must all be the same : HPV = (PHI)*Core (1 - Sw_core) = (PHIT) * (1- Swt) = PHIE * (1 - Swe) These application of static pay / reservoir cut-offs (will be more accurate if the static cutoff is calibrated with dynamic data ie PLT, well test) was invented in connection with the evaluation of clastic reservoirs which allow the petrophysicist to classify the penetrated rock sequence in intervals that would flow hydrocarbons (Pay) and intervals that would not (Non-Pay). The method works fine in some clastic reservoirs and allows the petrophysicist to remove the apparent presence of hydrocarbons in non-reservoir intervals and identify potentially water bearing sands within a sequence of hydrocarbon bearing sands. But it may also mask the fact that an incorrect petrophysical model has been chosenm therefore result, both in a more realistic HCIIP being calculated, and may also result in an error being missed. Current core and log data from shaly sand reservoirs are re-evaluated using several wells known log analysis interpretation. As tested, multimin and determenistics models (actually Sw is calculated from Sw model, ie Archie, Waxman Smits, Simandoux) all provide quite similiar Sw results and agree fairly well with Swcore corrected to reservoir conditions. The model give shows Sw result are close to Swt they are paired with total porosity for HPV calculations. They have previously been tought to give Swe not Swt and have been paired with effective porosity giving pesimistic HPV result. The Archie total prosity model also give useful but pesimistic results (due to clay ). The Archie effective porosity model give very pesimistic Sw and HPV results in shaly sand.

AAPG Datapages/Search and Discovery Article #90331©2018 AAPG Asia Pacific Region GTW, Back to the Future – The Past and Future of Oil and Gas Production in the Asia Pacific Region, Bangkok, Thailand, September 26-27, 2018