The common viewpoint or paradigm of the far-field hydraulic fracture geometry is changing. Data sets compiled over the last decade are incompatible with the conventional picture of a single, bi-wing, planar hydraulic fracture. These data sets include (1) recovered cores, (2) minebacks, (3) microseismicity, (4) overcores and borehole video, (5) treatment pressure response, and (6) surface tilts, in conjunction with advancements in laboratory simulations, studies of natural hydraulic fracture analogues, and improvements in numerical simulations. The single, planar, farfield fracture paradigm finds its roots and development in early theory and simplified laboratory studies that were pre-disposed to single, planar fracture geometry. Replacing the old paradigm is a new perspective that includes a strong potential for creating multiple, far-field fractures. The implications of multiple, far-field fracturing has resulted in adjustments to completion and stimulation strategies to address and affect the overall fracture geometry.
Introduction
Hydraulic fracture treatment technology has witnessed massive growth since the 30's saw the first acid stimulations and the 60's saw the "150 frac-150,000 gals of river water and 150,000 lbs of river sand pumped at 150 barrels per minute." One of fracture technology's last frontiers is the understanding and optimization of far-field fracture geometry and proppant placement. Prior to the last decade, the paradigm of far-field geometry was a single, bi-wing, planar fracture that opened against the least principal stress. Since the 80's, a growing body of data rebukes this paradigm and a new perspective is emerging. This new paradigm includes the potential for creating multiple, far-field fractures. As we discuss, the foundation of the new paradigm includes recent field studies, improved laboratory simulations, and advanced theoretical modeling.
When not wanted, multiple far-field fractures are a bane to well performance and reservoir performance evaluation and optimization. Multiple fracture development results in shorter, narrower, and less conductive fractures and increased costs.
Within this paper, we report the results of an extensive literature search, expert opinion discussions, and field experiences on the state-of-perspective and state-of-knowledge of far-field hydraulic fracture geometry. The literature search collected and reviewed approximately 285 key articles, reports, etc. We discuss a selected fraction of these within this paper.
Gantt Chart of Hydraulic Fracture Technology. Table 1 is a Gantt chart of developments in hydraulic fracture technology. It includes major contributions to the far-field hydraulic fracture geometry paradigms. The first two categories on the chart, Foundation Studies and Common Models, show the bases and development of the old paradigm. The remaining categories contribute to the emergence of the new paradigm. Note that the new paradigm is supported by data compiled only over the last decade and a half. The old paradigm began its formation in the 1930's.
The Old Paradigm
The old paradigm represents sixty-plus years of development based upon the concept of single fracture growth. Since only within the last decade have hydraulic fractures been cored or mined (discussed below), this concept is rooted in early theoretical and laboratory-block studies. Unfortunately, many of these studies were overly simplified, making them predisposed to single fracture development.
The early theoretical models assumed an uncased, fluid-filled borehole within a homogeneous, impervious rock mass and a uniform, in situ (i.e., tectonic) stress field with the borehole axis aligned with the maximum (i.e., vertical) principal stress. Pressurizing the wellbore opens planar fractures on opposite sides of the wellbore. Each fracture or wing propagates radially, along the intermediate principal stress trajectory. This model is not incorrect, but it is not representative of actual hydraulic fracturing. Critical effects of well completion are not included. These include (1) perforations; (2) fluid rheology; (3) pressure history, (4) initial fluids in the bottom of the wellbore; (5) formation properties and heterogeneities; and (6) near-wellbore effects. As we discuss, subsequent studies have shown each of these can affect far-field fracture characteristics.
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