Abstract

One of the major reasons of reservoir formation damage is fines migration during drilling operations. In this paper, three different water-based drilling fluids were used to test permeability reduction ratio with Turkish South Eastern sandstone and limestone core samples using a dynamic drilling fluid circulation system. The drilling fluids were prepared due to API specifications with non-treated bentonite fluid, Polymer-XT and PAC -XC at 11 different differential sticking pressures. The core plugs were saturated with brine after being vaccuumed and initial permeabilities were measured. After the circulation of drilling fluids for two and three hours, return permeabilities were measured from the other end of the cylindrical core plugs. The permeability reduced due to the invasion of the fines particles into the core plugs. The damage ratio concept was used for permeability reduction analysis as the ratio of the difference between final and initial permeability to initial permeability. The limestone core samples gave out the minimum damage ratio with the fluid including PAC-XC at a permeability damage ratio of 32% whereas sandstone core plugs resulted in 46% damage ratio. The highest damage ratio with non-treated bentonite fluid was obtained with sandstone core plug as 78.4 %. The optimum drilling fluid sustaining the least formation damage was determined. An exponential correlation relating damage ratio and filtration pressure was applied to the experimental data. The experimental and correlated results match accurately with each other. The correlation equation was linearized by taking natural logarithms of the both hands sides of the correlating equation. Correlation coefficients for each drilling fluid were determined. High regression coefficients around 0.90 were obtained. This correlation enables the determination of further damage ratios at different filtration pressures for sandstone and limestone core plugs.

Introduction

Prevention of formation damage through fluids used for drilling and well operations provides one of the key elements for the economic success of oil- and gas field developments. To select an optimum fluid for drilling or well operations in a reservoir section, one of the most prominent criteria is potential formation damage. Using representative formation cores, service laboratories conventionally measure the permeability impairment caused by candidate fluids to benchmark formation damage potential. During recent years, a number of studies have been carried out to develop the ability to evaluate well fluids in terms of their formation damage potential.

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