Porosity Partitioning and Flow Unit Characterization from an Integration of Magnetic-Resonance and Borehole-Image Measurements

Abstract

The petrophysical evaluation of carbonate reservoirs in terms of predicting the hydrocarbon potential is trivial. However, it is difficult to correctly predict the fluid flow in the absence of proper characterization of the different flow units encountered in these reservoirs. The process of identifying the flow units becomes non-trivial in the presence of extensive diagenesis process affecting the original depositional texture. The conventional triple combo logs gives an average response when logged against diagenetically altered zone thus overlooking or under-estimating diagenetic features occurring in micro scale. It becomes imperative to look at both micro and macro scale heterogeneity for evaluation of such reservoirs, which has a direct impact on the production, and water injection scheme of such reservoirs. The NMR data and image based secondary porosity estimation recorded in this well were used for partitioning the porosity into micro, meso and macro porosity. Borehole image logs have been interpreted in terms of defining the connectivity of the features seen on the image. This is then used to define a high-resolution connectivity index. An integrated approach using the NMR and the image is being proposed to identify such high permeability streaks that can explain the production performance or the water injection behavior at a later stage of development of the field. Based on the porosity partitioning technique an improved permeability estimate is made. The production results confirm the findings of this study. Introduction In order to link log data to the hydraulic properties of carbonate reservoirs, the oil industry is seeking better methods for characterizing the carbonates. This lead to the development of a method of carbonate rock classification keeping in mind the following key objectives and needs. Permeability prediction from logs is always difficult since no logging tool is available which can make direct continuous permeability measurements. Logging tools, instead, measure a surrogate for it such as a textural estimate from bore hole imaging logs or a pore size estimation from NMR logs. The interplay of multiple properties of the rock such as pore size distribution and texture influence the permeability to the extent to which pore throats are plugged with cement or other materials Numerous studies have shown that there is no direct relationship between the porosity and the permeability of the carbonate system. To understand the permeability of the reservoir a pore classification method may have to be resorted which can explain the production behaviour. The pore system classification would also help in designing a water injection program for such reservoirs. This study uses an integrated approach using the NMR and the micro-resistivity bore hole images for identifying and quantifying the secondary porosity and their impact on the permeability. This technique was validated from the dynamic behaviour of a well and shows promise in understanding the performance of the water sweep at the later stage of field development.

Petrophysical Evaluation of a Severely Heterogeneous Carbonate Reservoir; Electrical Image Logs Usage in Porosity Estimation

“…Also, cementation factor (m) was estimated as a continuous curve from borehole images and petrophysical logs [18] and shale volume calculated using binarization technique by electrical image logs [19]. Furthermore, in some studies it was attempted to separate and calculate vuggy porosity using electrical image logs [20] [21]. But the purpose of this study is to determine the effective porosity (primary and secondary porosities) using electrical image logs.…”