Oil production from a fractured reservoir, composed of a gas cap and an oil zone, is usually taking place using surface or submersible pumps. The pumps usually operate under constant withdrawal rate until gas breakthrough, at which time the pumping rate would be influenced by the presence of gas at the production side. It is evident that pumping rate dictates both pressure and fluid flow regimes in the volume which is under the drainage influence of the pump. The main focus of this paper is on the gas-liquid (G-L) interface behavior and recovery performance of employed models as a function of liquid withdrawal rate. A series of flow visualization experiments were performed using unconsolidated packed models of rectangular geometry with two fractures on the sides. Parametric sensitivity analyses were performed considering the effect of different system parameters such as fracture aperture, matrix height and permeability, well spacing and fluid viscosity on the Critical Production Rate (CPR), Maximum Possible Withdrawal Rate (MPWR) and G-L interfaces in both matrix and fractures.
Experimental results have shown that higher pumping rates cause higher difference between liquid levels in fracture and in the matrix, thus the gas breakthrough happens sooner. Moreover, it was determined that as long as the porous medium is drained with a constant liquid withdrawal rate less than critical, the height difference between G-L interfaces in matrix and fracture remains constant. In this paper, a new concept of "Critical Pumping Rate" (CPR) was defined at which each particular porous medium has recovery factor equal to the recovery factor for higher rates just before gas enters into the production well at the bottom, and also the difference between liquid levels in fracture and matrix remains unchanged at rates higher than this specific rate. Known this particular withdrawal rate, there are two main advantages, namely:
choosing a pumping rate lower than it to drain the reservoir without getting gas breakthrough; and
understanding the physics of pumping behavior from fractured media and extending the concept to the real cases. In addition, the maximum liquid pumping rate from each physical model has also been studied and it was found that this rate depends strongly on the storage capacity of the fractures, petrophysical properties of each model as well as physical properties of test fluids.
There are over 100 naturally fractured reservoirs (NFR's) in the United States and many more around the world containing an estimated 25–30% of the world oil reserves [1–4]. It is believed that naturally fractured reservoirs are among the most complicated class of reservoirs to produce efficiently. This particular type of reservoirs comprises of an interconnected system of fractures, which provides the main fluid flow paths, and the reservoir rock or matrix that acts as the main storage source of hydrocarbons.
From the geological point of view, it is plausible to distinguish between various classes of fractured reservoirs [3–9].