Prediction of Viscosity for Xanthan Solutions in Brines

Abstract

Loss of solution viscosity in brines of increasing ionic strength (salinity/hardness) is a major problem in the use of partially hydrolyzed problem in the use of partially hydrolyzed polyacrylamides for enhanced oil recovery mobility control. polyacrylamides for enhanced oil recovery mobility control. The solution viscosity of xanthan gum polysaccharide, however, is generally accepted to be polysaccharide, however, is generally accepted to be unaffected by salt content in the water. In fact, recent work by Philips, et al, has shown that solutions of high-pyruvate xanthan actually increase substantially in viscosity with increasing salt concentration.Earlier papers by Ward and Martin and French, Stacy, and Collins reported results of US DOE-sponsored programs to establish relationships between total ionic strength, concentration of calcium or magnesium ion, polymer concentration, and the resulting solution viscosity for partially hydrolyzed polyacrylamides with varying degree of hydrolysis and polyacrylamides with varying degree of hydrolysis and molecular weight. This paper presents similar work with xanthan biopolymers of varying pyruvate content. Formulae are given to enable prediction of solution viscosity for a given brine salinity and polymer concentration, and to calculate the polymer polymer concentration, and to calculate the polymer concentration needed to give a desired solution viscosity.For both medium- and high-pyruvate xanthans, solution viscosity increased with increasing brine salinity; the presence of multivalent cations (liardness) had no additional effect on viscosity beyond their contribution to total salinity. For a given polymer concentration, xanthan solution viscosity polymer concentration, xanthan solution viscosity exceeded that of hydrolyzed polycrylamides above about 0.3% total dissolved salt.Introduction. Although partially hydrolyzed polyacrylamides remain the most widely used mobility control polymers for tertiary oil recovery, xanthan biopolymers polymers for tertiary oil recovery, xanthan biopolymers have found increasing utility where moderate to high salinity produced brines are used for polymer dissolution. This preference for xanthan in saline solution is based primarily on cost: the viscosity of polyacrylamide solutions drops markedly with polyacrylamide solutions drops markedly with increasing salinity and hardness. Thus the somewhat higher cost per pound of xanthan still yields a lower cost per barrel of injection fluid because of the much higher concentration of polyacrylamide needed to give a certain viscosity in saline brines.The reduction in viscosity of solutions of high molecular weight hydrolyzed polyacrylamides by salt is caused by the association of cations with the negative charges along the polymer chain. This association screens the charges and prevents the repulsion which normally gives the polymer its extended configuration with very large hydrodynamic volume. In the presence of salt, the polyacrylamide molecule collapses into a tight ball with low hydrodynamic volume and low solution viscosity.Though it has a lower molecular weight than typical polyacrylamides (1.5–2 million vs 5–20 million), the xanthan molecule is extremely viscosity effective because it forms a relatively rigid rod with high hydrodynamic volume in solution. It is believed that the negatively-charged pyruvate terminated side chains in xanthan wrap around the pyruvate terminated side chains in xanthan wrap around the backbone, forming a multistranded helix and contributing to this rigidity. The presence or absence of salt cations has little or no effect on this basic rod-like structure so the solution viscosity is relatively unchanged in saline brines.Certainly other factors also affect the selection between xanthan and polyacrylamide for mobility control: shear stability, rock retention, injectivity, etc. These factors have been discussed elsewhere and will not be reviewed here. The effect of salinity on polymer solution viscosity is not of minor importance, as more than half of US petroleum reservoirs have brine salinities greater than 5% TDS (Table).P. 23