Abstract
Modern methodology of well testing is the result of efforts of many scientists for more than 50 years. It is mainly based on the theory of single-phase flow. Few publications consider two-phase flow. However, they were also generally reduced to single-phase inverse problems.
During the last several years, authors have been developing an alternative trend in well testing. Its distinctive features are:
creation of bi-directional two-phase flow in the nearwellbore region or forced creation of two- or three-phase fluid flow;
interpretation of well test results based on 1D, 2D or 3D multiphase optimization problems.
Obviously in this case well testing techniques are rather more complicated. They become science-intensive. On the other hand, they firstly extend the list of parameters and relations determined -those required for up-to-date 3D flow simulations. Added features include relative permeabilities for oil, gas and water, capillary pressures and full tensor permeability. Secondly, these parameters and relations characterize the effective (realistic) pore space. It is the effective, not absolute, pore space where the real reservoir flow processes take place. Turning to the effective pore space improves the degree of certainty in 3D modeling and enables proper use of well test results in the process of history matching 3D reservoir models.
The developed approach displayed noticeable advantages when applied to carbonate formations. In this case it enables more reliable characterization, compared to laboratory core experiments, including determination of
formation type (i.e. single- or dual-porosity) and
parameters and relations required for 3D dual-porosity simulations.
In the paper the authors present a review of results obtained up to date.
