FIELD-STUDY OF INTEGRATED FORMATION EVALUATION IN THINLY LAMINATED RESERVOIRS

The major problem in studying thin-layered reservoirs is identification of net pays and reliable assessment of hydrocarbon-saturation type and degree. The main difficulty arises from the low vertical resolution of standard resistivity tools. More specifically, in laminated formations, thinbeds of fine-grained sand, silt, and clay distributed within hydrocarbon-bearing formations significantly reduce the apparent resistivity. Such fine-grained thin-bedded layers can hold high volumes of irreducible water and thus produce water-free hydrocarbons; yet oil companies may not even attempt to complete such zones. For example, one offshore deepwater well off the east coast of India, was recently tested over two thinly laminated sand/shale zones and produced dry gas of approximately 34 Mscf/D. However, this gas production was not expected by the initial conventional normal resolution petrophysical evaluation, which was largely underestimating the hydrocarbon potential over these two tested zones. The problem becomes more acute in deepwater formation evaluation since exploration and development costs are much higher and thus it is essential that all hydrocarbon reserves should be accurately assessed. This paper is a case-study of a field-scale integrated thin-bed petrophysical evaluation and hydrocarbon reserve estimation in the field-A (offshore India). All the drilled wells in this field intersected thinly laminated shale-silt-sand sequences and blocky sands. It is shown that in this environment using conventional resistivity data to quantify the hydrocarbon reserves is difficult because the data are dominated by the conductivity of the shale laminae. A model has been developed to use two resistivity measurements (vertical and horizontal), in conjunction with other available logs (nuclear magnetic resonance and formation microresistivity) and core data, in order to better predict the potential hydrocarbon in place. The final results were compared with the ones derived by conventional petrophysical evaluation. Use of this technique in several gas-bearing, thinly bedded intervals has resulted in gas reserve estimate increases up to 700 percent of the conventionally computed reserves. These results are confirmed against a variety of independent data, including surface seismic interpretations, reservoir pressure profiles core analysis and well tests.