Many horizontal and highly deviated wells are drilled using the "drill-in fluids" introduced in recent years. The drill-in fluids are typically comprised of either starch or cellulose polymers, xanthan polymer, and sized calcium 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 flow capacity at the wellbore wall. This reduced flow capacity can result in reduced well productivity or injectivity consequently, wellbore acid treatments are typically applied in attempts to remove or "bypass" the filter cake. The acid treatments are often only marginally successful, particularly when applied in extended length intervals.
Extensive studies were conducted to develop laboratory procedures to better simulate and characterize the damage attributable to drill-in fluids, various chemical systems were subsequently applied to evaluate the effectiveness of their relative filter-cake degradation capabilities.
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. The data show that through utilization of this new technology, smaller, less costly treatments can be used to treat entire openhole intervals to zero-skin potential with dramatically improved treatment efficiency. Much smaller, lower concentration acid treatments can then be effectively applied to stimulate the interval. Surveys following the field application of the new system have shown not only increased flow, but also flow throughout entire length openhole intervals.
The practice of drilling wells in horizontal or highly deviated configurations, as well as multilateral completions, has developed rapidly in recent times. The purpose of this activity is to contact more hydrocarbon-bearing payzone area within a single well in order to maximize productivity. Such wellbores often penetrate thousands of feet of productive zone as opposed to the tens to hundreds of feet contacted in vertical well configurations.
The fluids, or muds, historically utilized in drilling applications for lubrication and cuttings transport typically contain high concentrations of clays such as bentonite. These are known to cause damage to the permeability of the near wellbore area due to leakoff and mudcake deposition on the face of the production zone. Thus, the formation damage can be related to both the filter cake and the filtrate that invades the productive zone. It is often necessary to apply stimulation treatments to these damaged intervals simply to bypass the drilling fluid damage. The recent development of new drilling techniques to maximize wellbore contact with the 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 drilling muds. The standard practice is to drill to the top of the payzone 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 or cellulose polymers, 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.