The formation damage caused by drilling fluid invasion around the wellbore reduces well productivity and changes the reservoir's original characteristics. In this context, drilling fluids specifically designed to perforate pay-zone, known as reservoir drill-in fluids, have been studied to optimize the drilling process and minimize formation damage. This work aimed to evaluate the brine-polymer drill-in fluids rheological behavior, invasion profiles of fluids and formation damage in carbonate and sandstone samples. For this purpose, polymer solutions was prepared using natural (XG) or synthetic (HPAM) polymers, solid-free or including CaCO3 as bridging agent. Rheological and statistical analyses were performed. In addition, invasion lab tests at constant pressure, followed by oil backflow, were run to represent, respectively, the processes of an overbalanced drilling and a natural clean-up. The displacement tests were performed using carbonate and sandstone samples at connate water saturation and the results were compared. Through rheological evaluation and statistic analysis, the polymer and its concentration were confirmed as the main regulators of viscoelastic characteristics and consistency index for XG formulations, while the CaCO3 addition caused significant changes only on HPAM formulations. The data of flow dynamics on carbonate samples pointed out that the oil productivity ratio (PR) was more reduced using XG fluid than HPAM one. This behavior was attributed to the higher elastic characteristics and consistency index of the fluid with XG, which provides higher flow resistance. These results were more significant when the CaCO3 was added to the formulation, i.e., the formation of a filter-cake led to a complete reduction of PR. Comparing the influence of the rock matrix, HPAM fluids invasion was faster for the carbonate sample than for the sandstone one, possibly owing to differences in wettability and heterogeneity as mentioned in the literature. During the clean-up process, all samples showed oil permeability or productivity ratio restoration, but at different rates and cumulative oil volume flooding.


Fluids used in overbalanced drilling, where the pressure exerted by the fluid on the borehole is greater than the reservoir pore pressure, can invade the reservoir and promote the reduction of permeability of the pay-zone. This problem is called formation damage. This way, the development of specific fluid technology for drilling the reservoir, known as drill-in fluids, has been intensified with a view to minimize this problem, optimize the drilling and maintain the properties of the reservoir contacted.

Brine-polymer drill-in fluids may have high viscosity because their composition typically includes polymeric additives, which act as viscosity agents and filtered reducers, salts and bridging agents, which contributes to the formation of filter cake (Civan 2000, Cameron 2001, Martins et al. 2005, Queiroz Neto et al. 2007, Petri and Queiroz Neto, 2010, Li et al. 2011).

Given the characteristics that are assigned to the use of these fluids, this work aims to evaluate the rheological behavior of brine-polymer drill-in fluids with synthetic (partially hydrolyzed polyacrylamide - HPAM) and natural (xanthan gum - XG) polymer, whether or not containing bridging agents, in order to correlate the rheological characteristics observed to the analyses of invasion of these fluids in porous medium and their removal with backflow in sandstone and carbonate samples.

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