Heavy-Weight Crosslinked Gel Frac Fluids – How Much Bang for the Buck DO We Really Get?

Abstract

As many of the shallow, higher perm reservoirs in the Gulf of Mexico deplete, wells are being drilled deeper into more challenging high-pressure, low permeability reservoirs. Casing and work-string sizes are also being downsized to reduce costs. This presents a challenge as many of these lower permeability reservoirs cannot be produced economically without a hydraulic fracture completion. To lower surface treating pressures to levels that can be managed within current frac boat and surface iron limits, heavy weight brines are often used as the base fluid for these frac gels. These fluids use the extra hydrostatic pressure of the brine to lower the surface treating pressure.1,2,3 However, some of the hydrostatic advantage from the brine density of these fluids is lost due to the additional friction caused by this same increase in density. This friction increase has been previously documented, and the precise magnitude of the increase has been discussed in several publications. Limited full-scale test data exists on the actual friction increase verses hydrostatic pressure for many of these fluids. Pre-job estimates from service providers indicate that there is a lack of understanding on the effects of high-density brines to the friction pressure of crosslinked gels. This is due to the excessive cost of full-scale testing, the limited market for these fluids, and the wide variations in deep-water well architecture. In this study, actual frac job data is analyzed from 30 frac stages in eight different wells with similar measured depths, true vertical depths, and work-string configurations. Five different base brine densities were used in these wells, with the work split between two service providers. The base brine density ranged from 8.7 to 12.5 ppg. Many of these wells incorporated bottom hole gauges to allow for a more accurate calculation of friction pressure during the treatments. The following analysis compares the expected surface treating pressure with the observed treating pressure at varying rates and proppant concentrations throughout these fracture treatments. This comparison will also provide the observed increase in friction pressure against the hydrostatic benefit for these fluids. The results indicate that the use of expensive high-density brines as the base fluid for frac gels may not provide the expected reduction in surface treating pressure. A simple mathematical model was built using an empirical correlation of the measured data to aid in the design of future wells. This analysis should be beneficial to both service company providers and completions engineer end users. The results should be used to manage the expectations in the use of weighed frac fluids. The data suggests that the friction increase when using brines with a density greater than approximately 11 ppg as the base fluid for frac gels exceeds the hydrostatic benefit. At brine densities greater than 12 ppg, the study indicates that a standard 6% NaCl frac fluid would have a lower surface treating pressure for the given well depth and selected work strings. It is expected that this analysis will encourage future data gathering and testing for these fluids as their use increases.