Determination of Skin Radius Caused by Drilling Operations in Naturally Fractured Reservoirs

Abstract

Drilling fractured formations by overbalanced method causes lost circulation of drilling fluid in fractures. The lost circulation in drilling fractured zones has been traditionally accepted due to inability to control its occurrence. Most of drilled wells in fractured oil zones after completion are conducted on acid job in order to obtain well flowing. If the radius of skin due to lost circulation of drilling fluid through fractured oil zones be determined, the volume of acid needed to conduct any acid job can be calculated. The main goal of this work is to obtain a mathematical model for determination of skin radius in naturally fractured oil reservoir wells. In this study, one vertical fracture is assumed to symmetrically intersect a wellbore. During a lost circulation drilling fluid enters the fracture and displaces formation fluid. The mechanism of lost circulation through the modeled porous medium is formulated using mass transfer phenomena. Obtained equations give concentration of the lost fluid with respect to time and position. Filtration of the drilling fluid at walls of the fracture is considered to be exponential which is ceased after mud cake is formed. A simulator is developed using derived equations in this work. The concentration of the drilling fluid could now be plotted against the position in the fracture and also against the position in lateral direction for each point in the fracture at a given time. These curves tend to be S-shaped. The position in the fracture at which the curve of concentration reaches zero could be considered to represent skin radius caused by drilling operation. Similarly the position in lateral direction at which the concentration reaches zero represents lateral penetration of the drilling fluid in the matrix from its corresponding position in the fracture. Introduction Drilling of a potentially productive formation can be expected to cause some skin damage. The seriousness of that damage depends upon the nature of the formation, the composition and properties of the drilling fluid, and the drilling conditions. Usually the drilling fluid pressure is greater than the formation pore pressure. As a result there may be invasion by whole drilling fluid and solids from the drilling fluid as well as invasion by drilling fluid filtrate. Most of the factors known to affect particle and filtrate invasion are not readily subject to control. For example, high differential pressure often must be tolerated. Scrapping action of bit and drill string cannot be eliminated. There are limits to adjustments that can be made in drilling fluid circulating rates. On the other hand, the filtration characteristics of the drilling fluid can be controlled to prevent invasion. Further protection against formation damage can be exercised by selecting a type of drilling fluid to limit or avoid undesirable interaction of filtrate with the formation.[1] During invasion, drilling fluid displaces formation fluid and causes a mixing zone with a resultant S-shaped concentration profile to develop. Dispersion phenomena may be attributed to several physical phenomena including molecular diffusion, velocity profile effect, series of mixing cells, stagnant pockets and variation in flow paths. All these phenomena except molecular diffusion are dependent on convection of fluids through a porous medium.[2] There are different methods so far provided in order to simulate dispersion in a fractured formation. These modeling approaches are divided into two main classes: continuum models and discrete fracture models.[3] Dispersion in fractured media is typically simulated using one or more of the following conceptual models:equivalent porous medium (EPM),dual porosity,discrete fracture network (DFN), orhybrid DFN/EPM approaches.[4]