Long horizontal and multi-lateral wells continue to be used in applications requiring high production rate. However, many of these wells suffer from low productivity due to incomplete filter cake removal. The obstacles encountered are the difficulty to ensure contact of the cleaning fluids with the filter cake throughout the whole interval, as well as controlling the reaction rate between the cleanup fluids and the filter cake to assure uniform dissolution.

The filter cake formed by water-based mud consists of XC-polymer, starch, CaCO3 particles and drilling cuttings. Today several chemical techniques (oxidizers, enzymes and acids) are available to break the polymers and dissolve CaCO3 particles that are present in the filter cake. The limitations of these fluids are fast reaction rates and corrosiveness provided by acids, especially at high temperatures. Also, cleaning fluids are not effective in heterogeneous formations where there are high permeability streaks, which will require using large volumes of the treatment fluids, but with poor performance.

One way to overcome problems associated with the heterogeneous nature of oil and gas reservoirs is to increase the viscosity of the cleaning fluids. This was addressed in the present study by adding a viscoelastic surfactant to the cleaning fluids (mainly enzymes).

Laboratory studies were conducted to examine the effect of viscoelastic surfactants on the performance of specific enzymes (used to break XC-polymer and starch). The apparent viscosity of the combined solution was measured as a function of shear rate (10 to 1,000 s-1) and temperature (77 to 212°F). A modified HPHT fluid loss cell was used to assess the effectiveness of the combined system in cleaning filter cake formed by water-based drilling mud. The effects of temperature, enzyme type and concentration; and surfactant concentration were investigated. Experimental results showed that the surfactant increased the viscosity of the solution. As a result, the rate of polymer degradation by enzymes had decreased. Solutions that contain enzymes and viscoelastic surfactants can give a uniform distribution over the whole interval, which will result in higher production rates. This paper will discuss various interactions of surfactant-enzyme systems and address the advantages and limitations of this system.


The use of horizontally drilled wells has increased dramatically during the past decade because they offer greater contact with the reservoir rocks. The effective production rate should be much greater for horizontal well. Unfortunately, the larger drainage area and longer wellbore also contribute to a larger exposed area and longer exposure time for the drilling fluid in horizontal wells. Therefore, severe damage caused by drilling fluid can have a considerable influence on the reduction of horizontal well productivity.[1]

Near-wellbore formation damage can result from many activities during drilling, completion, and production. One of the most pervasive damage mechanisms is pore plugging by solid particles from drilling mud, drilled solids, or particles from the formation.[2] It is not always possible to prevent formation damage, and well stimulation techniques have been used to remove or mitigate the effect of formation damage for more than half a century. Although conventional well-stimulation techniques have been used very successfully, they have significant limitations in long horizontal wells and in wells with multiple branches.[3]

More and more new wells have a tendency to be complex, with slotted liners or screen completions, maximum reservoir contact (MRC),[4] multiple horizontal sections and, in some cases, sensitive downhole instrumentation. Saudi Aramco's definition of MRC wells requires that the horizontal interval must contact at least 4,000 ft of the targeted reservoir(s).[5] Such wells would benefit from a stimulation method that eliminates the need for aggressive chemicals and the difficulties associated with fluid placement.

Drill-in fluids are generally water-based muds (WBMs) containing a viscosifier, a fluid-loss reducer, salts, and sized calcium carbonate particles. For temperatures less than 260°F, conventional polymers are used for viscosity and fluid loss control. Solid particles are added for pore throat bridging, where the particle size distribution (PSD) of the CaCO3 is defined and matched for the permeability range of the formation being drilled.

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