Knowledge of rock texture and wettability are vital for the static and dynamic description of carbonate reservoirs. Conventional log measurements are limited in their applicability for the quantitative assessment of these attributes. Rapid variations of texture in carbonates diminishes the usefulness of core measurements on samples of limited size. Obtaining representative relative permeability by restoring core to native reservoir conditions, especially the original wettability state, is also very challenging.The dielectric response of clean carbonate rocks exhibit characteristic frequency dispersion patterns which depend on their texture and wettability. Dielectric measurements with multiple frequencies have become available enabling us to extract this information by inverting the tool data using a dispersive petrophysical model.The dielectric response is primarily sensitive to water, and provides a measure of the water phase tortuosity, which is a combination of texture and wettability, captured in the Archie's exponents m and n. Previous work has demonstrated the estimation of m from pore size distribution obtained from NMR data using an effective medium model. Formation Resistivity Factor data from core is presented to validate the model-derived m. In this work we propose a way to combine the cementation exponent so derived with the textural answers from the dielectric measurement to make a wettability estimate. We also assess the wettability from 3D NMR stations, using the increase in relaxation of oil manifested as shortening of the oil T 2 signal due to partial wetting of the oil phase. The methods are illustrated on a dataset from a Cretaceous carbonate, onshore Abu Dhabi. The interval surveyed in the subject well straddles an oil/water contact (OWC). The n exponent value derived by the method shows that the rock above the OWC is oil-wet in varying degrees. The inference on wettability state from the NMR data further supports the conclusions.

Fluids saturations in new wells are usually derived from resistivity measurements, using locally selected or calibrated resistivity equations. Some drawbacks to resistivity measurements are multiple environmental corrections in high-angle wells, thin beds, washed-out boreholes, and complex invasion profiles. Moreover, the accuracy of Archie's equation may suffer from variable cementation and saturation exponents and unknown water salinity.A recently introduced comprehensive suite of consonant logging-while-drilling (LWD) nuclear measurements with linear mixing laws, is used to solve for minerals and fluid volumes independent of resistivity measurements. This requires the petrophysical properties of all the fluids present to be known. Another requirement for accurate formation evaluation is the mud filtrate invasion correction. While this poses no problem for multiple depths of investigation (MDOI) resistivity measurements that also read deep into the formation, there is no set rule to determine the geometrical factor of nuclear measurements to account for invasion. This paper describes an LWD time-lapse data acquisition scheme to circumvent invasion effects on nuclear measurments and to eliminate the need to specify some of the unknown petrophysical properties of the fluids present. Canonical-correlation analysis (CCA) is used to identify canonical variates that remain unchanged between a primary drill pass and a secondary wipe pass. Because these variates remain unchanged between passes, they are independent of the formation invasion status, and can represent the properties of either the virgin or the flushed zone, but not a combination of the two, as is typically the case of measurements whose volume of investigation samples both zones. These invasion-independent variates are then used in the petrophysical evaluation, instead of the standard logs which may otherwise vary with time.We used CCA in 2 carbonate examples to show how to 1) correct bulk density measurement in corkscrew borehole, 2) correct MDOI capture sigma measurements for invasion effect, and 3) perform volumetric formation evaluation without knowledge of the water and hydrocarbon endpoints and invasion parameters. The CCA approach is a significant new development in well log interpretation that removes uncertainties associated with unknown mineral or fluids petrophysical properties and invasion status.

The formation evaluation of any wildcat, exploratory and/or appraisal well is challenging due to scarcity of information with respect to reservoir presence, its characterization and the expected pressure. It is expected that hydrocarbon bearing reservoirs, especially those located in low resistivity zones and without core for calibration of physical properties, might possibly be overlooked as these are difficult to interpret from petrophysical logs for the presence or absence of hydrocarbons. An advanced surface mud gas acquisition and analysis system, based on membrane technology, was utilized for the first time in the United Arab Emirates. Advanced mud gas analysis and interpretation of conventional and unconventional carbonate reservoirs sections identified interesting hydrocarbon bearing zones which were subsequently confirmed by integration of core, electric log and well-test data. An exploratory well was drilled to explore the hydrocarbon potential of unconventional reservoirs and appraise the conventional carbonate reservoir. Reliable results were achieved in a highly challenging environment including petrophysical uncertainty and a variety of reservoir fluids present. The results from the advanced mud gas analysis were confirmed by down hole sample testing results. The approach developed can be modified or customized to explore/appraise a prospect to capture any hydrocarbon zones, including by-passed zones, and subsequently optimize logging and testing programs resulting in a reliable data set and cost savings.

Petrophysical evaluation in horizontal wells using standard logging while drilling (LWD) data is challenging, especially in thin reservoirs (~ 4 ft) bounded by dense resistive formation. These challenges are predominately associated with the propagation deeper depth of investigation (DOI) resistivity measurements and limitation in recording azimuthal data around the borehole.In thin reservoirs the currently used electromagnetic (EM) resistivity tools with deeper DOI are usually affected by proximal beds which results in inaccurate saturation estimation for the target zone. Add to that, the traditional way of computing saturation using average porosity and resistivity measurements neglecting the variation around the borehole; this may result over/underestimating the water saturation which is an important factor in the STOOIP calculation. This paper will discuss a "3D Petrophysical" approach utilizing a new technology that provides shallow azimuthal resistivity measurements around the borehole. The approach is used in integration with the available methodology of utilizing azimuthal density data to capture the variation in water saturation (Sw) around the borehole in thin heterogeneous carbonate reservoirs.