A Novel Approach for Azimuthal Permeability Estimation : Case Study of Heterogeneous Carbonate Reservoirs Offshore Abu Dhabi
Authors: Anurag A. K. , Mishra A. K. , BinAbadat E. K. , Hosany K. I. , Al Hashmi G. , Al-Harbi H. , Brindle F. R. , Kuliyev M. , Gzara K. 
Published: November 2017

Pore network complexity in carbonate reservoirs is the result of heterogeneous pore size distributions, diagenesis and fractures. Fluid movement through such reservoirs is difficult to model, and permeability depends on the scale considered. Existing permeability computations are empirical in nature, and simply estimate average permeability curves that are hard to upscale. A novel approach for azimuthal and dynamic permeability estimation that preserves formation heterogeneity information is presented through a case study of Jurassic carbonate reservoirs.

First, existing petrophysical procedures are extended to take advantage of most Logging-While-Drilling (LWD) data being available in azimuthal fashion as images, to produce azimuthal lithology, porosity and fluid saturation images that retain all the information present in the original LWD images, instead of average results. A new azimuthal permeability image, derived from invasion dynamics, complements the volumetric petrophysical analysis. In general, while drilling, mud filtrate volume is highly correlated to formation permeability, time after bit (TAB), differential pressure, fluid viscosity and mud properties. Therefore, formation permeability can be inverted from the knowledge of all the other parameters. Mud filtrate volume can be computed as an azimuthal image from collocated azimuthal resistivity images at multiple-depths-of-investigation (MDOI), and TAB of such images is readily available as a log. Differential pressure and fluid viscosity can be measured. Finally, mud properties are calibrated to achieve the best match against LWD formation pressure testing stations. A method to compute horizontal (KH) and vertical permeability (KV) from the azimuthal permeability image is also discussed.

LWD data from several horizontal wells were processed and the benefits of displaying the resulting volumetric petrophysical analysis images in 3D are discussed. The processed resistivity images confirm heterogeneous /complex formation texture, with thin layering (~ 1 to 3" thickness), different vugs' size and type (within beds, along bedding planes, or along fractures), burrows patterns, and open, closed, and drilling induced fractures. The formation permeability image results match oriented formation tester data with ~ 95% confidence, over the entire range of measured permeability (~ 0.2 mD to 2 D). Image-derived high-resolution KH and KV were computed at different scales, taking into account true bed thickness (TBT) computation. The High-resolution resistivity images were also processed to study fracture distribution, by fracture type, and to extract fracture attributes.

KH and KV can be used as direct input for smart completion design with Inflow Control Devices (ICDs), or Interval Control Valves (ICVs). The azimuthal volumetric petrophysical analysis and formation permeability results presented in the case study represent a step improvement in heterogeneous carbonate reservoir characterization, and constitute the first quantitative application of invasion physics while drilling to dynamic permeability estimation.