Many horizontal wells are drilled using the clean "drill-in fluids" introduced in recent years. The drill-in fluids are typically comprised of either starch or cellulose polymers, xanthan polymer, and sized carbonate or salt particulates. They were introduced to minimize the mud damage to the wellbore relative to that typically observed with conventional drilling muds. However, testing and experience have shown that insufficient degradation of the filter cakes resulting from even these "clean" drill-in fluids can significantly impede capacity at the wellbore wall. This reduced flow capacity can result in reduced well productivity or injectivity. Consequently, wellbore acid or oxidizer treatments are typically applied in attempts to remove or "bypass" the filter cake. These treatments are often only marginally successful, particularly when applied in extended length intervals. Formation damage, as well as filter-cake impairment, must be eliminated to realize the full potential of horizontal completions.
Previous laboratory studies have demonstrated that drill-in fluid filter cake can be effectively removed through the application of a newly developed technique incorporating an enzyme-based polymer degradation system. This treatment can be designed to degrade xanthan-based, starch-based or cellulose-based drill-in fluid. Following degradation of the specific polymer, the weighting and/or fluid loss control material is easily removed using smaller, less costly acid treatments.
Case histories of wells treated with the new enzyme technology compared to direct offsets treated with conventional acid or oxidative breaker treatments will be presented. Field experience has shown that through utilization of this new technology, smaller, less costly treatments can be used to treat openhole intervals to zero-skin potential with dramatically improved treatment efficiency. Production results have indicated that three-fold increases are possible when applying a two-stage enzyme/acid treatment to acid or oxidative treatments alone. Post-treatment production logs have indicated not only increased flow, but also flow throughout the entire openhole interval.
The recent development of new drilling techniques to maximize wellbore contact with productive intervals has been complimented by the parallel development of drill-in fluids. The drill-in fluids are formulated to provide the functionality of drilling muds to drill through the productive zone while minimizing the associated wellbore damage experienced with conventional drilling fluids. The standard practice is to drill to the top of the pay zone using the conventional muds and then switch to the cleaner drill-in fluids to drill through the pay.
The drill-in fluids are typically comprised of either starch, cellulose or xanthan polymer and sized calcium carbonate or salt particulates. The starch or cellulose polymers provide viscosity for friction reduction and lubrication while the xanthan polymer enhances cutting transport capabilities. The particulates, which are removable, provide fluid loss control. Although drill-in fluids are inherently less damaging than the conventional drilling muds, relatively impermeable filter cakes are nonetheless still deposited on the borehole wall. Insufficient degradation of the filter cakes resulting from even these "clean" drill-in fluids can significantly impede flow capacity at the wellbore wall. This reduced flow capacity can result in significant reduction of the well productivity or injectivity. Formation damage from drilling fluid leaking off into the formation, as well as filtercake impairment, must be eliminated to realize the full potential of horizontal completions.
A common approach to minimizing damage during the drilling of openhole horizontal wells is to use a brine-based drill-in fluid system with acid or water-soluble weighting agents followed by the application of acid or an oxidative breaker system to dissolve filter-cake solids and polymers.