Permeability From Production Logs—Method and Application
Authors: Sullivan Michael J. 
Published: June 2014

Distinguished Author Series articles are general, descriptive representations that summarize the state of the art in an area of technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and present specific details only to illustrate the technology. Purpose: to inform the general readership of recent advances in various areas of petroleum engineering.

Estimating effective permeability at the reservoir scale has been a long-standing challenge in carbonate fields. The carbonate depositional and diagenetic history can be very complex, which can lead to permeability that is difficult to characterize. Vuggy or fractured intervals can have permeability significantly higher than the matrix permeability measured in core plugs. This "excess permeability" may control reservoir flow paths but is difficult or impossible to predict from static well-log transforms that are calibrated to matrix permeability.

In the Tengiz field, a giant carbonate reservoir in western Kazakhstan, a method has been developed to calculate apparent permeability on the basis of flow rate from production-logging tools (PLTs). Incorporating this flow-calibrated permeability into the Earth model offers an elegant solution to the long-standing problem of the best method to incorporate dynamic PLT data into a reservoir model. Recently, a reservoir model built with apparent permeability resulted in more-realistic heterogeneity and a step-change improvement over previous methods in which only static log-based permeability transforms were used to populate the Earth model. Fewer changes were required to calibrate the full-field reservoir model. History matching to pulse tests showed that this model has a much-improved prediction of the interwell connectivity. Models containing apparent-permeability data have provided higher-confidence estimates of the future movement of gas injection from the Tengiz platform.

The apparent permeability is calculated by solving Darcy's law on an interval basis, using our knowledge of flowing and static pressures as input along with well, reservoir, and fluid properties, and then calibrating with the pressure-buildup transient permeability-thickness product, kh. Accuracy of the method is enhanced by the derivation of coarse-scale zonal layer pressures with multirate PLTs. Selecting an appropriate skin factor to use in the calculation is important. The acid effect on pulsed-neutron-capture (PNC) logs works well in Tengiz and has been helpful in addressing this problem.

Introduction

The fundamental building blocks of a reservoir model are porosity, permeability, and fluid saturation. Porosity and fluid saturation can be computed from wireline logs with reasonable confidence, but often, the same confidence is not possible for permeability. Permeability can be measured directly from core material or determined with well tests by use of pressure-transient tests (PTTs), pulse tests between wells, and wireline formation tests. Scale differences in these sources of permeability data complicate the permeability estimation in a reservoir model (Al-Henshiri et al. 2005; Ahmed et al. 1991). In most reservoirs, the amount of core available for direct permeability measurement is limited, and permeability estimates usually are made by proxy by use of wireline-log responses. The science of permeability prediction has evolved into a high degree of sophistication, with each additional level resulting in an incremental gain in predictive accuracy (Skalinski and Sullivan 2001). Despite the available sophisticated tools, permeability prediction in carbonates remains problematic. The widely varying pore structures (Lucia 1995) and their potential lack of connectivity result in a highly variable porosity/permeability relationship. Vuggy porosity and fractures, if they are connected, can result in extremely high layer flow rates or very low rates, if not connected, for the same value of porosity.