With decreasing accessible oil and gas reserves, secondary and tertiary modes of EOR (enhanced oil recovery) are increasingly being used. WAG (water alternating with CO2 gas) injection for oil production alters the chemistry of carbonate reservoirs exacerbating the already prevalent issue of mineral scaling in oil field production wellbores, tubing, and surface equipment. In this work, produced water samples from two WAG fields in West Texas experiencing predominantly gypsum and calcite scaling are analyzed. Several analytical methods for measurement of cations (calcium and magnesium) and anions (chloride, sulfate, and alkalinity) are compared. The detection limit for very low-level sulfate measurement in high ionic strength brines using ion chromatography is established. Gypsum and calcite saturation indices are calculated and interpreted at varying field conditions and empirically validated with solid scale sample analysis. As it was determined that scaling occurs in well and tubing prior to already equilibrated water being sampled at surface, a 1-D Reactive Mixing-Material Balance Coupled Model is developed to provide insights on the scaling in the West Texas fields. An aerial streamlining mixing mechanism in which slow moving equilibrated carbonated injection water mixes with faster moving formation water right at the wellbore is deduced to be the in-situ mixing mechanism resulting in the observed scaling at the West Texas field. Based on 12 model runs with 4 different injection water fractions and 3 different analyzed surface sample compositions, 11 out of 12 runs qualitatively validated the observed calcium sulfate and calcium carbonate scaling in the field. In these 11 runs, the model’s predicted surface calcium concentrations differed from measured calcium concentrations by 8.3% to 27%. This study also includes preliminary scale inhibitor testing and scale inhibition recommendations.