Phosphonic/Hydrofluoric Acid: Tortuosity Remediation for Fracturing Treatments
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 152624, ’Phosphonic/Hydrofluoric Acid - A Promising New Weapon in the Tortuosity-Remediation Arsenal for Fracturing Treatments,’ by Ricardo Melo, James Curtis, SPE, Julio Gomez, SPE, Alexandre Melo, Fernando Garcia, and Helio Pedrosa, SPE, Baker Hughes, prepared for the 2012 SPE Hydraulic Fracturing Technology Conference, The Woodlands, Texas, 6-8 February. The paper has not been peer reviewed.

Tortuosity is one of the biggest challenges for shale and tight gas hydraulic-fracturing treatments, leading to high near-wellbore frictional pressure loss, premature screenouts, reduced treating rates, and poor production results. A new solution demonstrated substantial success in overcoming particularly stubborn tortuosity problems. The method builds on the use of a nondamaging, single-stage phosphonic-/hydrofluoric-acid system (SAS) for matrix-stimulation treatments.

Introduction

Hydraulic fractures are initiated and kept open by pressure. The pressure is transmitted by the pumped fluid, so as the pumping rate increases, so does the pressure. Following this process, stress is induced in the rock around the well-bore. If the pumping rate continues to increase, so does the stress. Eventually, a stress limit will be reached at which point the rock can no longer sustain the applied stress and it fractures.

Over a long perforated interval or in deviated wells, fractures can initiate anywhere, provided that the fluid pressure gradient exceeds the fracture gradient, either to initiate fractures or to reopen natural fractures. Generally, the rock will fail at its weakest point and the fracture will initiate there. However, if the pressure continues to rise, additional fractures may be formed because of changes in near-wellbore stress, as shown in Fig.  1. Later, the fracture will reach its natural direction, according to the formation’s stress orientation. Every perforation is a potential source of fracture initiation. Many of these fractures will be very small, but some may be large enough to take a significant portion of the treatment fluid.

Despite the artificial-stress environment generated around the well-bore, hydraulic-fracture treatments tend to produce a small number of larger fractures. Because of increased stresses around the fracture faces, individual fractures tend not to join together. The stress regime around the fracture faces can cause fractures to repel each other. However, with the complex stresses around the wellbore and perforations, fractures can join together at some point, connecting through narrow paths, sometimes with bends toward a main large fracture. Therefore, the treating fluid must flow from a region containing many small narrow fractures to a region containing a few large fractures. In following this path, the fluid must move through a series of convoluted, bending, and narrow fractures (i.e., a tortuous path). This tortuosity can produce a significant pressure loss, resulting in a smaller-than-expected fracture or in early screenout. Such screenouts might also be caused directly by tortuosity because these channels through the rock often are not wide enough for the proppant to pass through, causing the proppant to bridge and prevent further flow of proppant.