Characterization of Fracture Network System of the Midale Field

Abstract

Enhanced oil recovery from challenging/complex fields requires extensive analysis of reservoir structure and good understanding of the effect of this structure on the dynamics of the process. Naturally fractured reservoirs are good examples of this kind and their fracture network characterization is still a bigchallenge. In this study, we analyzed the fracture network system of a portion of the Midale Field, a naturally fractured carbonate reservoir in the Williston Basin of southeastern Saskatchewan, Canada. Our study aims at an extensive characterization of fracture and fracture network properties and construction of a reliable fracture network model for further use in assessing the oil recovery by CO2 injection and CO2 sequestration potential. We integrated static data such as cores, logs and well tests to build 3D discrete fracture network models. Stochastic numerical approach was applied using a commercial software package. A fracture network constructed from static data was calibrated using well test data. Several parameters were evaluated in sensitivity studies to determine those characteristics of the network which have higher influence on the reservoir performance. Simulated well test response was checked against previously published well test data. This study allowed us to recognize uncertainties in critical parameters and propose some measures to manage those uncertainties. Introduction The Midale is a carbonate field located in southeastern Saskatchewan. Following the discovery in 1953, the field was developed on 32 ha spacing and proved to bear 81.9 ? 106 Sm3 reserves of 28.7 °API oil. The field belongs to the Mississippian oil trend located along the northern margin of Williston Basin. Subsequent to primary production up to 1962, the field was subjected to waterflooding on 83 inverted nine-spot patterns. To maintain the production which declined after 1964, an intensive program of vertical and horizontal infill drilling was undertaken. As of the end of 2006, approximately 1,000 wells exist in the field and more than 25% of OOIP was produced with an average watercut of 92%(1). The Midale Field is currently being subjected to tertiary recovery by miscible CO2 flooding. This field-scale CO2 injection was preceded by a 1.78 ha pilot project in 1984 ? 1989 which paved the way for a larger demonstration project. The CO2 Flood Demonstration Project encompassed 10% of the Midale Unit and paved the way for the field-scale application, which is expected to end up with an incremental recovery of 15% of OOIP(2). The Midale Field does not meet typical screening criteria for CO2 flooding. Nevertheless, extensive research and field applications proved that a proper design based on the analyses of the special combination of petrophysical, lithological and fracturing data can result in a successful carbon dioxide flood. The 24 m thick Midale Reservoir section consists of two main layers: dolomite-dominated "Marly" and vugular limestone, called "Vuggy". Both strata contain systematic fractures, though the degree of fracturing varies. Numerous studies conducted on the field revealed some characteristics of the natural fracture network (NFN) by both inverse methods, such as waterflood and carbon dioxide flood performance analyses, and well test analyses and direct methods such as core and log analyses.

Pressure-Transient Behavior of Continuously and Discretely Fractured Reservoirs

“…Almost all the cores contain some natural fractures (Beliveau et al 1993); the cores indicate that the fractures are vertical to nearly vertical and open, and the fracture height and spacing range from a few inches to a few feet (Beliveau et al 1993). More recently, detailed information about the formation and fracture characteristics of the Midale field was given by Bogatkov and Babadagli (2009). Beliveau et al (1993) conceptualized the fracture system, as shown in their Figs.…”

“…We make several observations. First, if the major fractures trend in the northeast/southwest direction with approximately 1-ft fracture spacing, any well must have intersected a number of fractures because they cannot be drilled exactly vertical, and because the average dip calculated for all fracture sets is approximately 80 (Bogatkov and Babadagli 2009). Furthermore, Bunge (2000) reported that fractures intersecting the wellbore were observed from microresistivity imager logs.…”