Abstract

This paper presents results of field measured "dynamic" fluid loss for a high-temperature borate crosslinked HPG gel under high shear fracturing conditions in a partially depleted, moderate permeability gas reservoir. While most laboratory studies of dynamic fluid loss have been performed on low-permeability cores (<0.1 md) at constant shear rates, recent focus has turned to measuring this all important parameter on moderate to high permeability cores under realistic shear conditions. One such study showed that high shear-rates prevent gel filter cake buildup on the fracture walls and result in much higher fluid loss than commonly reported static results. The findings reported in this paper, from two gas wells in the Cooper Basin of Central Australia, provide field verification of this and one of the few discussions of dynamic fluid loss in an actual high shear environment. This should serve as a guide for future field testing and further the understanding of fluid loss under such conditions. It also provides insight into treatment design when high conductivity is required in moderate to high permeability formations having conditions condusive to high fracturing shear-rates.

Introduction

Moderate to high permeability, depleted gas wells can exhibit high shear rates in the fracture which, in turn, can cause fracturing fluid degradation, high fluid loss, and difficulty in fracture width development. In recent years service companies and others have turned their attention to the measurement of dynamic fluid loss under realistic shear conditions. One such study (1994) investigated the effect of shear-rate on fluid loss behavior of borate crosslinked (XL) gel and showed difficulty in forming a filter cake. This study also looked at the effect of shear on the placement of solid leak-off particulates and found that shear forces could be such that the particles might not reach or remain on the fracture walls. Field hydraulic fracturing results discussed herein seem to support these findings.

Results are from two Tirrawarra formation gas wells located in the Cooper Basin of Central Australia; each exhibiting permeabilities of 8–10 md, reservoir pressures of only 0.23 psi/ft, and rock modulii (E') of 5-7x10**6 psi. Both exhibited high skins on pressure buildup and the desire was to perform "tip-screenout" (TSO) fracture treatments to by-pass damage and create a high conductivity flow path to the undamaged reservoir. These were the first such treatments performed in this basin.

Prior to the first treatment, three minifracs were performed as dictated by the unbelievably high fluid loss, the last using a mixture of fluid loss additives. In each case, the bottomhole fracturing pressure was around 5300 psi, the pressure drop (dP) across the fracture face was in excess of 3000 psi, and fluid efficiencies were only 3-5%. This suggested that (1) the crosslinked gel might not be forming an effective filter cake and (2) leak-off could not be controlled with the concentrations of fluid loss additives tried. Modeling of the minifrac BHTP's, using a psuedo-3D fracture model, indicated shear-rates in the fracture of 350–1000 sec-1. Basing the final design on the minifrac efficiency, the first treatment was pumped to completion with the TSO occurring at the approximate time predicted. This lent support to the high leak-off, high shear environment. Results on the second well were virtually the same. Of importance, the TSO technique served to increase fracture width and lower shear-rate, resulting in higher fluid viscosity and better proppant transport than would have been possible with a conventional design. A discussion of pre-frac testing, job design, and treatment analysis are presented along with a parallel discussion of reported laboratory results.

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