Abstract
Abstract
A systematic approach for interference tests in reservoirs with double porosity behavior is presented; it applies to both naturally fractured presented; it applies to both naturally fractured reservoirs and multilayered reservoirs with sufficiently high permeability contrast between layers.
Type curves are presented for the pressure response at an observation well, the active well being produced at either constant flow rate or constant pressure. They are derived from two models with the assumptions of pseudo-steady state or transient interporosity flow regime. The distinctive specific features they exhibit are clearly identified and quantitatively related to the model parameters.
An interpretation method, based on type curve matching, is proposed: after selection of the most appropriate model, and identification of the successive flow regimes, the double porosity behavior of the reservoir is characterized and pertinent parameters are evaluated: flow conductivity kh, interporosity flow parameter lambda, and storativity (phi Vc t)h segregation parameter lambda, and storativity (phi Vc t)h segregation throughout the reservoir.
Actual field examples are discussed to illustrate the method.
Introduction
The paper is concerned with formations composed of two porous media or systems of different porosities and permeabilities, that distinctly contribute to the production process. One medium presents a high production process. One medium presents a high conductivity and thus drains the reservoir fluid to the producing well, whereas the other medium presents a producing well, whereas the other medium presents a much lower conductivity and feeds fluid only to the more conductive system. Because the storativities of both media usually differ by several orders of magnitude, these formations are referred to as double porosity formations, while they are actually characterized porosity formations, while they are actually characterized by a high permeability contrast between media.
The success of field development projects as well as stimulation operations for such reservoirs requires an accurate evaluation of reservoir performance, i.e. knowledge of the storativities and flow characteristics of both media. For this reason, and because reservoirs with double porosity behavior are recognized as major contributors to the world hydrocarbon and geothermal production, they have been the subject of many studies over the last years.
The concept of a double porosity model was first introduced by Barenblatt, et al. They considered a fissured reservoir and defined for each point in space two pressures: the average fluid pressure in the fissure system -the most conductive- pf, and the average fluid pressure in the matrix system -the less conductive- pm, in the neighborhood of the given point. Furthermore they assumed that the flow of fluid from the matrix to the fissures occured under a pseudo-steady state regime: pseudo-steady state regime: (1)
where q* is the interporosity flow, namely the flow from matrix to fissures, and alpha a shape factor representative of the interporosity contact area. A solution was given for the pressure distribution in the matrix system, assuming a negligible fissure storativity.
Warren and Root presented the solution for the pressure distribution within the fissure system. They pressure distribution within the fissure system. They showed that two parameters were sufficient to characterize the double porosity model:
(2)
(3)
lambda is the interporosity flow parameter, related to the ability of the fluid to flow from the matrix into the fissures; w is the ratio of the storativity of the fissure system to the storativity of the total-fissure and matrix -system.
Later on, Mavor and Cinco-Ley extended Warren and Root's solution to take into account the effects of wellbore storage and skin.