Development of a Dual Crosslinker Fracturing Fluid System

Yaritz, Joseph (Halliburton Energy Services Inc.) | Stegent, Neil (Halliburton Energy Services Inc.) | Bailey, Tom (Halliburton Energy Services Inc.) | Fritcher, Eddie (R. Lacy, Inc.)



Studies of the production histories of wells in the Cotton Valley (CV) region of east Texas led companies to recognize the potential value of optimizing fracture design in this area. As a result, chemists developed a dual crosslink fluid (DCF) system that performs best at high temperatures and moderately high pH levels and uses guar as the gelling agent. The new system has enhanced viscosity and an adjustable crosslink rate.

Because the CV sand formation is a "tight gas sand" region, drilling companies have focused on reducing fracturing costs without hindering well production. The use of the DCF system has resulted in fewer screenouts than Zr-guar systems in the CV formation, and it is a more economical alternative to fracturing fluids that use guar derivatives, such as hydroxypropyl guar (HPG) and carboxymethyl hydroxypropyl guar (CMHPG) as the polymer.

By using a moderately high pH and combining the borate crosslinker with a zirconium (Zr) crosslinker, operators have been more successful at placing proppant in a fracture. The performance of previously used Zr-guar-based fluid systems was often unpredictable at the higher temperatures. The DCF crosslinkers have a synergistic relationship; the viscosity of the combined system is higher than the sum of the separate systems' viscosities. The new system improved operational efficiency to greater than 96% in over 85 treatments last year in the CV region. Gas production from wells treated with DCF is similar to that of the higher-priced CMHPG and HPG fluid systems that use zirconium as the crosslinker. Description of the Region

Gas production from the Cotton Valley (CV) formation, which includes 14 fields in east Texas, has grown steadily since 1978. Divided into three major areas - Carthage, Oakhill, and Waskom - the depositional system is a transgressive-regressive marine sequence bounded by the Bossier shale below and the Travis Peak formation above (Fig. 1, Page 6). The formation sediments were deposited in a dominantly progradational sequence of shallow marine and fluvial-deltaic environments. The CV formation is Upper Jurassic and is about 1,200 to 1,500-ft thick at depths ranging from 8,000 to 11,000 ft. The area is divided into two major intervals: the upper Cotton Valley (UCV) and the Taylor Sand. In 1980, the low-permeability CV sandstones were classified as "tight gas sands" by the Federal Energy Regulatory Commission (FERC). Permeability of the productive CV sands is typically between 0.01 and 1.0 md. with porosities up to 15% but generally in the 6 to 8% range. Numerous depositional analogs to the CV system exist worldwide.

History of the Problem

Since the 1970s, operators have used a variety of hydraulic fracturing techniques in the CV formation to stimulate production in the wells that typically produce below the predicted rate.

When a preliminary study in 1990 revealed that two out of three CV wells produced below the expected rate for the field, a team of engineers from several companies drilling in the CV area conducted an extensive study to determine the reasons for the vast production swings. The team developed an analytical technique to assess completion practices and determine key parameters that would help operators predict degrees of economic success for specific wells. Results from the study led engineers to conclude that optimizing fracture designs could improve results from the underproducing wells.

Because the CV sand formation is a "tight gas sand" region, drilling companies have focused on reducing fracturing costs without hindering well production. Improvement in fracturing techniques over the past several years has increased efficiency and reduced fracturing costs by 36% over previous treatments. However, engineers decided to try to reduce cost further by using guar as the base polymer instead of high-cost guar derivatives (CMHPG and HPG).