Changes in Near Wellbore Stress and Fracture Gradient Due to Cold Water Injection in a Sirte Basin Field, Libya

Abstract

It is important to understand the effects of introducing thermal changes in the subsurface because such changes alter the state of stress and, ultimately, the behavior of the formation. Inducing fractures in the formation may cause injection fluids to advance at different rates through the reservoir, thereby reducing the areal sweep through the reservoir and the overall efficiency of a flooding operation. To avoid induced fractures, it is necessary to maintain water flooding operations below the fracturing (breakdown) pressure of the formation. For these reasons, it is extremely important to model the cold water injection response and to predict whether it is possible to inject without creating fractures in the formation. In late 2006 a reservoir simulation study using ECLIPSE was performed for 103N Field in Sirte Basin to evaluate the reservoir response to water flooding in an attempt to understand the potential for improving oil and gas recovery with water flooding. This study showed that the main effect of cold water injection on the recovery of N- Field was reduced injectivity due to high water viscosity. Another effect of cold water injection was that bypassed oil was cooled down and its mobility was reduced due to the increase in the oil viscosity, thus reducing ultimate recovery. This paper provides an extension of the reservoir simulation done by Wintershall to examine the effect of cold water injection on formation fracturing gradients. The work includes a review of the rock mechanics and stress analysis of the subsurface formations and provides an estimation of fracture penetration within the reservoir for a range of water injection rates and water surface temperatures. The conclusions of this study provide important insights into applying water flooding operations in the N-field. Introduction Undisturbed subsurface temperatures typically increase from surface to bottom hole. In oil and gas wells, reservoir temperatures of 150 °F to 350 °F are common. These reservoir temperatures remain relatively constant during the primary production phase of a oil or gas reservoir, that is, most primary production occurs under isothermal conditions. All points in the subsurface are subject to a state of stress in addition to temperature. This state of stress occurs as a result of the depositional environment and subsequent tectonic forces applied to the formation. The stresses, both from rock matrix and pore fluids, are resolved for any point in the formation and represented as a system subjected to three principle stresses. When fluids are injected into a well, such as during water flooding or tertiary recovery processes, the temperature of the fluids injected is typically cooler then the in-situ reservoir temperature. Continuous injection of this colder water creates a thermal gradient around the wellbore, with the coldest temperature at the wellbore and the warmest temperature at a point ahead of the injection front. The heat transfer (cooling) which occurs is a function of the formation porosity and permeability, the injection rate, and the initial thermal differential.