Often and for many reasons the wellbore does not completely penetrate the entire formation, yielding a unique early-time pressure behavior. Some of the main reasons for partial penetration, in both fractured and unfractured formations, are to prevent or delay the intrusion of unwanted fluids into the wellbore, i.e. water coning.. The transient flow behavior in these types of completions is different and more complex compared to that of a fully penetrating well.
This paper proposes a method for identifying, on the pressure and pressure derivative curves, the unique characteristics of the different flow regimes resulting from these types of completions and to obtain various reservoir parameters, such as vertical and horizontal permeability, fracture properties, and various skin factors. Both naturally fractured and unfractured (homogeneous) reservoirs have been investigated.
For unfractured and homogeneous formations, a spherical or hemispherical flow regime occurs prior to the radial flow regime whenever the penetration ratio is twenty percent or less. A half-slope line on the pressure derivative is the unique characteristic identifying the presence of the spherical flow. This straight line can be used to calculate spherical permeability and spherical skin values. These parameters are then used to estimate vertical permeability, anisotropy index and skin.
For a naturally fractured formation, the type curves of the pressure and pressure derivative reveal that the combination of partial penetration and dual-porosity effects yields unique finger prints at early and transition periods. These unique characteristics are used to calculate several reservoir parameters, including the storage capacity ratio, interporosity flow coefficient, permeability and pseudo-skin. Equations have been developed for calculating the skin for three partial completion cases: top, center and bottom. The analytical solution was obtained by combining the partially penetrating well model in a homogeneous reservoir with the pseudo-steady model for a naturally fractured reservoir.
The interpretation of pressure tests in both systems, i.e. fractured and unfractured reservoirs, is performed using Tiab's Direct Synthesis (TDS) technique for analyzing log-log pressure and pressure derivative plots. TDS uses analytical equations to determine reservoir and well characteristics without using typecurve matching. These characteristics are obtained from unique fingerprints, such as flow regime lines and points of intersection of these lines, that are found on the log-log plot of pressure and pressure derivative. It is applied to both drawdown and buildup tests. Several numerical examples are included to illustrate the step-by-step application of the proposed technique.
Over the last four decades, naturally fractured reservoirs have been a topic of continuous research due to the fact that many producing fields of the world are found in such type of formations. These reservoirs differ in geological and petrophysical properties from homogeneous reservoirs.
Additionally, in many oil and gas reservoirs the producing wells are completed as partially penetrating wells; that is, only a portion of the pay zone is perforated. This may be done for a variety of raisons, but the most common one is to prevent or delay the intrusion of unwanted fluids into the wellbore.
