Quantifying Hydrocarbon Saturation in the Highlands of PNG

Abstract

An accurate estimate of hydrocarbon saturation is essential in calculating volumetric reserves but is often one of the most difficult petrophysical parameters to quantify. The evaluation of water saturation has been particularly challenging in reservoirs in the Highlands of Papua New Guinea (PNG). Experience gained from logging, coring and evaluating exploration, development and production wells has led to an improved understanding of petrophysical responses and reservoir properties. A significant challenge has been acquiring true formation resistivity measurements, as factors in the drilling environment and reservoir properties can result in suppressed resistivity responses. As a result, water saturations derived from resistivity-based methods have been found to commonly overestimate water saturation when compared to other methods, such as core-based capillary-pressure-derived saturations. Such limitations of conventional resistivity-based evaluations have led to the requirement of more complex logging programs and extensive coring efforts to better define water saturation. Examples are given from recently drilled wells at the P’nyang and Muruk gas fields where resistivity data was acquired in multiple runs over the same depth intervals. These time-lapse datasets demonstrate a substantial decrease in apparent resistivity over time. This is attributed to deep filtrate invasion penetrating far enough to affect the response from deeper-reading resistivity tools. At the P’nyang South-2ST1 well, resistivity logs acquired first on a logging-while-drilling (LWD) pass, then 55 hours later on a measurements-after-drilling (MAD) pass, show a substantial decrease in resistivity which equates to an apparent water saturation increase of up to 25% for that specific reservoir. Analysis of these datasets has provided insight into the extent of invasion effects on resistivity, the potential impact on evaluating water saturation and subsequently on field volumetric estimates. These observations have also helped reconcile differences between resistivity-based and core- or NMR- based water saturation evaluation methods. Moreover, they have highlighted the potential uncertainties associated with using a resistivity-based water saturation estimate at other wells in the Highlands, particularly where it is the only source of water saturation data available. To address these challenges it is recommended to integrate a variety of data sources and evaluation methods for quantifying water saturation. The preferred workflow uses core-based capillary pressure measurements, acquired using the porous-plate technique, to build saturation-height functions. This requires representative cores be cut and comprehensive Special Core Analysis (SCAL) programs undertaken. Where wells have been drilled with oil-based mud systems and cored, Dean-Stark extraction of fluids should be undertaken to give direct measurements of water saturation. The inclusion of NMR tools in logging programs provides valuable independent estimates of bound fluid volume within the pore space. In addition, high-quality capillary pressure measurements can be achieved on large-diameter rotary sidewall cores, such as those recently acquired at P’nyang South-2ST1. Integration of these datasets can help identify and mitigate issues associated with resistivity-based water saturation evaluation and reduce uncertainty in quantifying hydrocarbon volumes.

AAPG Datapages/Search and Discovery Article #90371 © 2020 AAPG Asia Pacific Region, The 1st AAPG/EAGE PNG Geosciences Conference, PNG’s Oil and Gas Industry: Maturing Through Exploration and Production, Port Moresby, Papua New Guinea, February 25-27, 2020