Adsorption of alkali on rock surfaces is a well-established phenomenon in high total acid number oil reservoirs, particularly noticeable during alkali-polymer (AP) flooding. Despite this, the influence of alkali on the degradation of polymers in these environments remains insufficiently understood. This study explores the role of alkali in enhancing the viscosity stability of polymers under shear stress conditions prevalent in porous media.
Utilizing polyacrylamide polymer products supplied by two vendors, AP slugs were prepared for this work. Coreflooding experiments were conducted at injection velocities representative of field-scale operations to induce and study the degradation of polymer chains. These experiments were enabled to assess the rate of polymer degradation, for which viscosity measurements served as a primary metric. To encompass a range of field scenarios, injection velocities varied from 1 to 20 ft/D. Additionally, core plugs with both low and high permeability were used to replicate the diverse shear rates encountered in heterogeneous reservoirs.
Our findings demonstrate that AP slugs exhibited lower viscosity loss during core flow, resulting from a combined effect of brine softening, reduced adsorption, and chemical aging at high pH. These changes are likely attributed to the increased anionicity caused by alkali. Another contributor could be the role of alkali as changing rock surfaces to be positively charged, which seems to reduce polymer adsorption, thereby helping to maintain the viscosity of the produced polymer solutions.
Core plugs with lower permeability exhibited higher shear rates, leading to a marginally greater breakdown of polymer chains and consequently more significant viscosity reduction in effluents. As anticipated, higher injection velocities, which simulate the conditions near wells, resulted in greater viscosity losses.
In comparing the two polymer products, the product from Vendor B showed superior viscosity control, whereas the product from Vendor A exhibited enhanced propagation in porous media. The injectivity outcomes for core floods in the presence of crude oil (two-phase) align with those from single-phase core floods when injecting polymer/AP slugs. The reported viscosity behavior reflects the combined effects of chemical aging, brine composition, and flow-induced stresses and should not be interpreted as a direct measure of mechanical degradation. The enhanced recovery factor attributed to the AP slug injection (23% vs. 2%) is confirmed to the result not only from the in-situ saponification process but also from the increased viscosity retention of the AP slug.
This study not only sheds light on the flow dynamics of polyacrylamide polymers but also underscores the importance of viscosity retention in situ. Such stability is a critical factor affecting both injectivity and mobility in porous media. Therefore, it is imperative to consider these findings as part of the screening criteria for field applications, especially where AP flooding is used. This research thus provides a pivotal step forward in understanding and optimizing polymer-based enhanced-oil-recovery techniques in challenging reservoir conditions.
This abstract is taken from paper SPE 229906 by M. Tahir, R. E. Hincapie, D. Steineder, T. Clemens, A. Farzaneh, and S. Mikulic, OMV Exploration & Production GmbH.The paper has been peer reviewed and is available as Open Access in SPE Journal on OnePetro.