Quantifying Proppant Transport for Complex Fractures in Unconventional Formations

Abstract

Since the widespread proliferation micro-seismic fracture mapping, it has been observed that some naturally fractured formations exhibit a non planar or complex set of micro seismic events. This fracture mapping technique has provided some valuable insight into the nature of this complex fracturing. However, this mapping is not necessarily a direct measurement of hydraulic fracturing. Instead the microseisms are small shear failures in the rock that can be caused by changes in pressure and temperature of the formation. Therefore we cannot know with certainty if these events are directly showing us where the proppant or even the frac fluid is going. None the less, this insight to complex fracturing, has been key to improving economic recovery of many unconventional plays over the past 8 years. However much of the improvements, have been through empirical trial and error and qualitative techniques. For example it had been observed that thin fracturing fluids tended to create more complex fracturing than viscous fluids. More recently it has been observed that smaller mesh proppant may be more successful at being transported out into the multiple fracture planes of the formation than larger mesh proppant. Although this trial and error technique has been useful, it is often very slow and can be expensive, it took many years to optimize the Barnett play in the Ft. Worth basin. But even more detrimental is when a success from one basin is applied in another basin without fully understanding the underlying mechanics. This can often lead to costly disappointment. This paper reviews the key parameters that need to exist to enable complex fracturing such as:○Nature and genesis of the natural fractures.○Orientation of the minimum and maximum horizontal stress.○The juxtaposition of the natural fractures to the stresses.○Magnitude of the difference between the minimum and maximum horizontal stress.○Poisson's ratio and Young's modulus of the rock being stimulated. From this information we attempt to quantify the dilation pressure of natural fracture systems which precede complex fracturing. But in particular we attempt to investigate the mechanics of the critical intersection of these transverse fractures and how they can interfere with each other and create pinch points that can inhibit non planar proppant transport. The ultimate goal of this paper is to demonstrate a methodology for quantifying the width relationship of these intersecting fracture systems, which can be used to determine if multi planar proppant placement is possible and help design the optimum mesh size and net pressure required to enable successful placement. Introduction: As conventional resources for natural gas become depleted, unconventional resources become more and more important for meeting our natural gas energy needs. It is estimated that currently more than 7 tcf of natural gas production per year come from unconventional tight gas, coalbed methane, and shale gas1. With extremely low matrix permeability formations, natural fracture enhancement of the formation permeability becomes important and many times essential for economic exploitation. The degree of influence natural fractures have upon reservoir formation permeability, storativity and completion effectiveness varies greatly and depends upon many parameters such as the origin of the fractures, fracture digenesis, the stress on the natural fractures, and stress orientation. Unfortunately many of these parameters are not always well understood when completion and stimulation decisions are made.

A review on hydraulic fracturing of unconventional reservoir

“…Different spacing will lead to different stress condition which can prevent/enhance secondary hydraulic fractures [88]. Moreover, contact area between hydraulic fracture and rock matrix has been enlarged by increase the fracture complexity or networking [59,66]. Even in some cases, bottomhole pressures were varied between zones, and this difference could impact on in-situ stress profiles and affect the fracture propagation [46].…”

Numerical simulation of hydraulic fracture propagation in tight oil reservoirs by volumetric fracturing

“…Due to the small fracture width, as the hydraulic fracture propagates, the volume of liquid that is injected into the fractures will be reduced. Therefore, it is hard to inject the proppant into the fractures thus leading to sand plugging (Olsen et al 2009). On the other hand, if the horizontal stress difference is high, the fracture propagation becomes difficult if the horizontal well has a close fracture spacing.…”

Geomechanics and Flow Parameters that Influence Shale Gas/Shale Oil’s Design

“…mineral composition, rock mechanical properties, horizontal stress difference and natural fracture properties. Brittle mineral-rich shale is beneficial in maximizing fracture complexity, whereas high clay mineral content is harmful in stimulating the reservoir [13,14] listed four conditions that made fracture complexity in the Barnett shale a desired and possible outcome: extremely low matrix permeability, low Poisson's ratio, low horizontal stress difference, and orthogonal regional tensile fractures. The importance of natural fractures in shale for hydraulic fracturing treatments has been particularly studied by Gale et al [15].…”