The economic decision to develop a new field depends heavily on the reservoir quality which, in turn, is based on two factors: the storage capacity and the flow capacity of the reservoir. The former is controlled by the porosity and hydrocarbon saturation and the latter is control by the permeability. This crucial information are computed using sets of logging measurement which is often supported by routine and advanced core analysis data. The process of comparing the log based interpretation with the core results can be time consuming and costly. New developments in logging technology especially in geochemical and dielectric logging are aiming to improve the log derived interpretation and reduce the uncertainties of the evaluation. This paper presents a case study where the integration of the advanced and standard logging tool is used to reveal the true potential of a gas reservoir.

For Chevron in Western Australia the standard formation evaluation is usually based on spectral gamma ray, resistivity, density, neutron, sonic and magnetic resonance logs. This logging suite has been proven successful in determining the reservoir quality in clean gas sand reservoirs. However in new frontier fields the uncertainty becomes larger due to complex mineralogy, the choice of saturation equation, unknown formation salinity and the paucity of SCAL data. In this case study, the standard logging suites does provide a reasonable result, however, the introduction of the geochemical log reveals the existence of iron-rich heavy minerals, which suggests a higher calculated porosity after mineralogy correction. The dielectric log being sensitivity to water permittivity was used to measure the irreducible water volume independent of the inputs needed by a typical conventional water saturation method. In oil base mud environments, the dielectric log can measure the irreducible water in the reservoir as it is not displaced by the oil base filtrate. This advanced formation evaluation shows an increase of 22% gas in place in a particular compartment.

A continuous permeability measurement can usually be inferred by the magnetic resonance log based on the free fluid and bound fluid ratio using the Timur-Coates equation. The bound fluid volume is determined by using a typical T2, 33 ms cutoff. However, the paramagnetic minerals in the formation are known to cause alteration in magnetic resonance relaxation time. In this example, the paramagnetic minerals caused a faster transverse relaxation time, hence a higher bound fluid will be computed if the T2 cutoff is not adjusted. This phenomenon has been a difficult challenge to solve in our industry. A new approach to compute the permeability was tried in this study where the irreducible water computed from the dielectric log was used as the bound fluid. The free fluid was computed by subtracting the total porosity with the dielectric irreducible water. The Timur-Coates permeability using these inputs is more consistent with offset data and confirmed by the mobilities from the formation pressure testing tool. The new approach reveals an almost 300% increase of flow capacity compared to conventional methods in the studied section.