Improved Prediction of Permeability and Reservoir Quality Through Integrated Analysis of Pore Geometry and Openhole Logs: Tar Zone, Wilmington Field, California
Authors: Davies D.K. , Vessell R.K. 
Published: December 2007

Abstract
The permeability of potentially productive, deep water (turbidite) Tar Zone sandstones in Wilmington Field ranges over several orders of magnitude for any value of porosity. This complicates formation evaluation. Variations in permeability for a given value of porosity are the result of variations in pore geometry. Quantification of pore geometrical attributes, using SEM-based pore image analysis, allows for identification of five rock types: intervals of rock with similar pore geometry, porosity-permeability relationships, and capillary pressure characteristics.
Accurate prediction of permeability in these loosely consolidated, high porosity sandstones requires a knowledge of both rock type and porosity. Algorithms have been developed (using core measured data) that allow for prediction of permeability from a knowledge of rock type and porosity. Individual rock types are identified using wireline log response characteristics, specifically;cross-plot of apparent grain density versus the logarithm of the absolute value of the separation between Rxo and Rt,thin section calibrated values of Vshale, andSP response. Where zones have been influenced by steam, considerable suppression of neutron porosity response is observed.
In such zones, the neutron porosity curve is reconstructed by regressing Rhob and data.
Rock types are identified rapidly in all wells on a foot-by-foot basis using a standard wireline log suite (SP, OR, Resistivity, Density, Neutron) no new logs, no specialized logs are required. Net footage of each rock type is determined for each well location and zone. This allows for rapid, computer-based mapping of the distribution of each Rock Type in non-cored wells. Thus reservoir quality can be readily predicted on a fieldwide basis from a knowledge of rock type distribution.

Introduction
This study presents techniques for improved prediction of permeability and flow unit distribution in a high porosity, heterogeneous sandstone. It focuses on the integration of pore geometrical data and wireline log data to develop an improved formation evaluation methodology for complex sandstone reservoirs. The study is funded by the US Department of Energy as part of its Class III Oil Program for "Slope/Basin Clastic (SBC) Reservoirs". An objective of this program is to develop and demonstrate advanced reservoir characterization tools that will improve evaluation and increase reserves in this and other SBC reservoirs.

Production History and Reservoir Characteristics
This study concentrates on the Tar Zone of Fault Block IIA, in Wilmington Field, California (Figure 1). Wilmington Field was discovered in 1936. It is the third largest oil field in the United States, based on total reserves. Approximately 2.4 BBO have been produced to date from an OOIP of 8.8 BBO. In the Tar Zone, the oil has a gravity of 140 API and a viscosity of 360 cp and Fault Block IIA is on steamflood Production history is summarized in Table I. Fault Block IIA is developed using a 7-spot pattern with a well spacing of 7.5 acres and currently has 39 injection and 57 production wells. Steam is supplied at the rate of 395 mmbtu/hr, 1250 psig at 80% steam quality (25,500 bbl/d cold water equivalent). Reservoir pressures are maintained at 700–900 psi to prevent surface subsidence. Temperatures in the steam chest reach 500–540 F.
The Tar Zone produces oil from two, unconsolidated, fine grained, lithologically complex (arkosic) sands in the Pliocene Repetto Formation (T and D Sands, Figure 2). These sands were deposited in heterogeneous, turbidite reservoirs. P. 129