Extension of Acid Fracture Penetration by Drastic Fluid-Loss Control

Abstract

Summary Creation of an optimum etched fracture length in an acid fracture treatment is often a problem because of high acid leakoff through the wormholes. This paper presents a unique acid system, compatible with most carbonate formations, that controls fluid loss in the wormholes. Production and treatment pressure data validating successful fluid-loss control and improved fracture extension also are presented. Introduction Acid fracturing is a well-stimulation process commonly used in carbonate reservoirs. HCI is usually injected into the formation above the fracture pressure to create a fracture or to open existing natural fractures. Unlike proppants, acid etches the fracture faces unevenly, creating on closure a highly conductive channel for the reservoir fluid to flow into the wellbore. The key to the success of hydraulic fracturing is the achievement of fracture penetration, conductivity, or both, depending on the formation permeability. In general, in lower formation permeabilities, penetration is more important than fracture conductivity for optimum production. From experience and mathematical simulations, it is believed that. for similar fluid and petrophysical properties, adequate fracture penetration is more difficult to achieve in acid fracturing than in propped fracturing. This paper presents state-of-the-art technology available to mitigate acid penetration problems and discusses the importance of acid penetration in carbonate formations. Carbonate Formations Carbonate formations normally show secondary porosity and permeability because of the presence of natural fissures. The limestone matrix generally is very tight, with high storativity but very low transmissivity or permeability. Exceptions include dolomites or oolitic limestones where primary or intergranular porosity and permeability often are present. Low-permeability carbonate formations are natural candidates for hydraulic fracturing. These formations have very tight matrices and are naturally fissured. In pressure-transient tests, these reservoirs often exhibit dual-porosity behavior. Such transient behavior presumes that the matrix stores most of the fluid and slowly transmits it to the fracture network, while the fracture network produces the fluids into the wellbore. These natural fractures or fissures often are damaged by scaling or calcification, especially in the presence of flowing water at high temperature. The scaling process intensifies at the natural fracture nodes with large pressure losses, such as at the wellbore or where hairline fractures intersect with major fracture arteries. The resulting blockage of major fracture arteries drastically impedes flow into the wellbore. Matrix acid treatments (i.e., treatments that do not induce fractures) clean up such blockages at or near the wellbore. However, depending on the spatial density of the fracture or fissure network, the wellbore of very restricted dimensions may or may not intersect an adequate number of these fractures or fissures. Consequently, matrix treatments may fail to clean up an adequate number of fissures with sufficient penetration to stimulate the formation effectively. Thus, matrix acidizing in naturally fissured carbonate formations often fails to provide sustained improvement in production.