Abstract Most formation evaluation measurements like neutron, density and resistivity, can be influenced by the drilling fluid and by mud filtrate solids. The severity of fluid invasion is mainly a result of the type of mud and the depth of investigation of the individual measurements. Wireline (WL) operations often occur days after drilling a section of a well, and the invasion of mud filtrate into the formation can be significant, making fluid saturation profiles difficult to interpret. Logging-whiledrilling (LWD) acquired data are less affected by invasion because the data are acquired in a close-to virgin formation condition. However, in addition to the impact of invasion, resistivity can be affected by ‘artifacts’ like the presence of conductive or resistive minerals in the formation. These minerals can lead to misinterpretations that affect conventional saturation calculations. For exploration drilling, nuclear magnetic resonance (NMR) is often used to obtain an independent fluid saturation profile for comparison with conventional petrophysical data. However, NMR is a very shallow measurement, and differentiating between hydrocarbons in place and oil-based mud filtrate invasion can be very difficult if fluid signatures are similar, even when using 2D NMR. In such situations an independent source of information is vital to separate between formation fluid and the borehole fluid invasion effect.
A vertical exploration well located in the Norwegian Sea was drilled to TD at 4025m. The primary target was the Early-Middle Jurassic Fangst and Båt Gps reservoirs deposited in a shallow marine-to-deltaic environment. Reservoir quality was relatively low with average porosity of 14% and maximum of 20%, and permeability was in the range of >1–10 mD. The secondary target was a pinch-out trap in the Cretaceous Lange formation, consisting of thin sands deposited in a marine environment. Porosities were similar to the Jurassic formations, however permeabilities up to 200 mD were seen from sidewall cores.
This paper presents a case where conventional petrophysical evaluation based on basic formation evaluation data from LWD and WL is compared to the results from 2D nuclear magnetic resonance-based fluid saturations. Mineralogical information to aid in the interpretation of the conventional data was derived using neutron-induced gamma ray spectroscopy. The validity of the analysis was evaluated using a new approach to interpret surface logging gas data, based on C1 up to C5 including the isomers of butane and pentane, which are totally independent and not influenced by filtrate invasion. Using this technique, a high-resolution hydrocarbon type and distribution log was created to prove the presence of hydrocarbons in place.