Analysis of Finely Laminated Deep Marine Turbidites: Integration of Core and Log Data Yields a Novel Interpretation Model
Authors: Reedy Gary K. , Pepper C. Fred 
Published: December 2007

Abstract
Description of Paper. Selection among alternative log analysis models is based on the accuracy with which each can predict specific properties. The assessment of predictive accuracy involves core data not used for log calibration. Model selection is made using set of accuracy and vertical resolution criteria, based on both data quality and the requirements of the planned application (e.g., mapping, simulation).
The log and core data used in this study are from deep marine reservoirs containing finely laminated sand/shale sequences in which the sand fraction exceeds 70%. Combined effects of thin laminations, variable sand properties, and high shale conductivity, complicate log analysis efforts. Several conventional log analysis models we evaluated provided satisfactory estimates of hydrocarbon pore volume, but none achieved the accuracy required for reservoir flow simulation. A new model was developed based on lithofacies relationships derived from integration of core, log, and geologic data. This model was subjected to the same calibration and testing as the conventional models, and achieved the desired level of predictive accuracy. The test results allowed the model to be applied with confidence to over 2000 feet of uncored pay.
Technical Contributions:A method for selecting among alternative log analyses by evaluating predictive accuracyA case study of an integrated evaluation of log, core, and geological informationA simple and accurate log analysis model for finely laminated deep marine turbidites

Introduction
Deep marine turbidite deposits have become the focus of considerable exploration and development activity worldwide, and particularly within the "deepwater" area of the Gulf of Mexico. This study involves the Green Canyon 205 Unit (GC 205), located 150 miles south of New Orleans in an average water depth of approximately 2600 feet (Fig. 1). A development project for GC 205 is currently being pursued, with Chevron as Operator, and participation by partners Exxon and Fina.
The geologic setting, facies distribution, and reservoir architecture for the major sands in this field have been previously described by Rafalowski, et. al. Most of the reserves in this field are contained within very finely laminated sand/shale sequences, with individual lamina often less than one inch thick. Even micro-imaging logs typically have insufficient resolution for quantitative determination of the net reservoir fraction in these formations. Since the shales in these reservoirs have high neutron porosities, moderate density porosities, and high conductivity, accurate assessment of the shale volume (VSh) is critical to all log analysis calculations. Early log analysis efforts were adequate for assessment of original hydrocarbon volumes in-place. However, they did not provide sufficiently accurate characterization of other reservoir parameters required for fluid flow simulation. The need for such simulation to assist with development planning prompted a review of the log analysis methods being used and available options.

Data Availability and Quality
Well Log Data. Of the ten penetrations drilled within the GC 205 unit, eight encountered oil sands in one or more of the six recognized development horizons. Figure 2 shows the locations of these penetrations with respect to the combined productive limits of the six horizons. Four of these reservoirs are grouped into the Lower Pleistocene "Nebraskan" series (Neb 1, Neb 2, Neb 3U, and Neb 3), while two sands are recognized within the Upper Pliocene series (14200' and 14800'). The Neb series sands contain the bulk of the developable resource, and were the primary focus of our study.
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