Geology and Geometry: A Review of Factors Affecting Hydraulic-Fracture Effectiveness

Abstract

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 97993, "Geology and Geometry: A Review of Factors Affecting the Effectiveness of Hydraulic Fractures," by R.B. Willis, SPE, and J. Fontaine, SPE, Universal Well Services Inc.; L. Paugh, SPE, Great Lakes Energy Partners LLC; and L. Griffin, SPE, Pinnacle Technologies, prepared for the 2005 SPE Eastern Regional Meeting, Morgantown, West Virginia, 14-16 September. Thousands of wells are hydraulically fractured in the Appalachian basin each year with little clear understanding of what the resulting fracture actually looks like. A number of subsurface features exist that can influence the ultimate dimensions and orientation of a created fracture. It is necessary that the stimulation design team understand the influence these features can have on the path of a subsurface hydraulic fracture. Introduction The majority of Appalachian basin reservoirs require some type of stimulation to be economical. Because neither the reservoir nor the created fracture can be seen or assessed with any real certainty, it is necessary to make assumptions about how the reservoir geology will respond to stimulation. Some assumptions that have been accepted over the years were controversial at first but have gained general acceptance over time. Other design factors are the result of local conclusions based on the results of treatments that have been refined through years of modification. Traditional methods for predicting fracture growth include computer modeling, treatment-pressure analysis, radioactive tracers, and well testing. Microseismic imaging, a technique that images the created fracture by monitoring seismic or microearthquake "events" during the treatment from an array of sensors in an offset wellbore, has gained wide acceptance over the past 5 years as a reliable method of determining created-fracture geometry. These measured created-fracture-geometry results need to be related to production from the stimulated intervals to determine fracture effectiveness. Where production improvement is obvious, the stimulation style usually will be accepted and applied over a large region rather quickly. This can be seen in the shallow reservoirs of the Bradford group, where operators are steadily increasing the number of fracture stages, which directly correlates to increased production. However, for deeper horizons, there are few documented cases in which production results have been rigorously shown to correspond to certain stimulation-treatment designs. The highly competitive nature of regional leasing and the difficulty in obtaining good treatment data and production information make correlating job type and profits a daunting task. A good first step is to better understand the created-fracture geometry for a particular fracturing style in a given reservoir. Basic Fracture-Growth Concepts It is generally accepted that hydraulic fractures propagate perpendicular to the least principal stress. It follows that in shallower environments where the least principal stress is vertical, a fracture will grow horizontally. At some depth, where the increase in overburden causes the least principal stress to be horizontal, the pre-dominant fracture-growth geometry will be vertical. It follows that a hydraulic fracture will respond to stress and propagate in the direction of least resistance. Variations in stresses between different lithologies in vertical rock sequences can cause fracture growth in a contained manner and generate length or allow the fracture to grow vertically upward or downward. Compounding the difficulties in attempting to predict how a fracture will grow are the many other features that can be present such as faults, natural fractures, bed laminations, and other reservoir characteristics that would be difficult to know or predict from the surface.