A major operator has used a novel approach to improve the performance of stimulation fluids in high-permeability, deepwater completions. A concentrated breaker solution is pumped into the formation before the introduction of crosslinked gel. This breaker solution improves cleanup of fractured and non-fractured perforations during high-permeability fracturing operations. This technique was developed because laboratory testing indicated that conventional breakers can be consumed by sediments, resulting in less than optimal gel breaks. This observation, when combined with the knowledge that whole crosslinked gel leakoff occurs in high-permeability formations, makes it necessary to pre-treat the near-wellbore region with a sacrificial concentrated breaker.
This paper includes studies on core materials with specific mineral compositions to determine the effectiveness of the concentrated breaker technique. Interaction between fracturing-fluid breakers and formation materials has been investigated at temperatures between 120° and 225°F. Core-flow experiments measuring the amount of active breaker present in the fluid exiting the core have also been performed with both enzyme and oxidizing breakers, and retained breaker activity of enzyme and conventional oxidizing breakers was compared.
Enzyme stability is affected by the presence of minerals as well as the formulation of the stimulation fluid. A comparative study performed at 175°F showed that breaker activity decreases as temperature increases for both a conventional oxidizing breaker as well as a stable, high-temperature oxidizing breaker. However, at 225°F the stable, high-temperature oxidizing breaker maintained some activity upon exiting the core.
This paper highlights three successful applications of the concentrated breaker solution in the Gulf of Mexico (GOM). These successes are compared to performance from offset wells, providing a benchmark for identifying the benefits of this new process.
Frac-packing has become a common method for bypassing near-wellbore damage induced by drilling and completion operations, allowing operators to achieve high-productivity, low-skin completions. However, evidence suggests that some high-permeability formations (kh>80,000) do not respond as favorably to fracturing as theory would suggest. High skin values have been reported for several fracture completions performed in high-permeability, deepwater GOM wells.1–2
The effects of non-darcy mechanical skin may explain the higher skin values.3–4 As fracture flow capacity (kh) increases, non-darcy skin becomes a significant portion of the total system pressure loss, suggesting that methods for removing damage, reducing non-darcy skin in high-rate, high-kh wells, and increasing the contribution of the non-fractured perforations should greatly impact the total skin of the completion.
For high-permeability completions, several potential damage mechanisms may contribute to high skin values, including poorly gravel-packed perforations, perforation tunnels with limited cross-sectional area, and damage from completion fluids. Frac-packing can bypass damage in the near-wellbore fracture plane. However, in high-permeability wells, it can also initiate whole-gel leakoff into the formation through the non-fractured perforations.
Advances in fluid technology have minimized the residual polymer in the formation and the damaging effects of whole-gel leakoff. These advances include highly efficient fluids that require less polymer as well as advancements in breaker technology.5–6 However, recent work has shown that the effectiveness of breakers can be impaired in the presence of formation minerals. For example, persulfate breaker decomposition is significantly accelerated in the presence of sandstones.7–8