Three Petrophysics Techniques Applied for the Thin Lamination Reservoir: The Impact towards Significant Reserve Addition
Authors: Fadjarijanto A. , Rachmadi A. , Setiawan A. S. , Praptono A. , Suriyo K. , Simatupang M. H. , Pakpahan O. , Costam Y. R. , Zakaria Z. U. 
Published: March 2018

Fluid identification is a key component of formation evaluation and becomes one of the important parameters that underlie economic decisions in field development. The combination of high clay content in the thinly laminated shaly-sand reservoir, together with unknown water salinity, increases the complexity in the accurate quantification of hydrocarbon-bearing reservoirs. The inherent clay distribution affects the log data response of high gamma and low resistivity analyses. Those responses can lead to incorrect interpretations unless other log data responses are considered.

The low resolution of a common oil-based resistivity tool often fails to capture structurally complex, thinly laminated sand-shale formations. The low resistivity response results from high resistivity sand layers suppressed by low resistivity shale layers, which can result in misinterpretations of calculating high water saturation. Observations of other conventional well log data can provide early qualitative identification of the low contrast zone. Data from the Thomas-Stieber method, resistivity anisotropy, and high-resolution micro-imaging are available to reconstruct conventional log data to provide an enhanced vertical resolution for final interpretations.

A field study was performed in the North Malay basin. Geologically, the field has three-way dip closure, bounded by a west-dipping fault to the west. The early evaluation of the DS2-B layer was interpreted as shale zones following a high gamma and low resistivity reading. Further observation of the density, neutron, and shear sonic trend do not provide the same shale indication. The decision was made to run a formation tester tool and to investigate any possible hydrocarbon indication. Real-time fluid identification and sampling proved the DS2-B layer to be gas-bearing and indicated that the conventional petrophysics-calculated water saturation was too high. Three petrophysics re-evaluation approaches were performed to define the reservoir challenges, including deterministic, Rv/Rh methods, and high-resolution data approach to obtain a better definition. All available data were used on the methodologies, based on the data required for each method, particularly the use of high-resolution imaging and core data for conventional logs to define the high-resolution of porosity, clay volume, and water saturation. As a result of these analyses, the DS2-B layer was proven to be a pay zone with a lower water saturation, which correlated with the formation sampling and core analysis results. The methodology has a proven capability to identify low contrast zones and can provide better interpretation in the field study through providing more a precise and accurate net-to-gross calculation.

The correlation and calibration of the conventional well log data to high vertical resolution image log, core data, and fluid sampling have provided a means of better visualizing and understanding the features of thinly bedded reservoirs in the field study. All methods were performed to calculate the final fluid saturation in highly laminated reservoirs. The new interpretation has proved a significant contribution to the NM field economic value.