A local field in central Louisiana was purchased as a personal investment by an operator. Since the operator had recently switched to a different sales gas company, the field was now required to meet a lower maximum allowable content specification of 2.0% CO₂ in the sales gas. With the decreased production specification for CO₂ levels, the well was no longer able to sell gas without undergoing chemical treatment.

The operator’s primary objective was to minimize chemical injection volumes, treatment costs, or both. Since the operator was also the owner, the decision on how to treat remained within the operator’s control.

SLB first treated the gas with a concentrated product (corrosion inhibitor) via a continuous atomized injection to reduce the CO₂ concentrations within specifications. The goal was also to reduce the volume of chemical needed for CO₂ scavenging. Another test yielded a much more effective, diluted product—a CO₂ scavenger GT-7540.

The first test—using the corrosion inhibitor—worked versus the third-party product. The corrosion inhibitor reduced CO₂ levels from 2.2% to 1.9%. But, based upon further testing and observation, the CO₂ scavenger proved more effective, reducing CO₂ content to 1.7% on average. The more diluted product helped with the gas/liquid interfacial contact time and efficiency. Field measurements by a third-party gas testing company, regularly used by the operator, also supported these observations. The CO₂ scavenger GT-7540 was applied at a rate of 4.26 L/d continuously, upstream of the sales gas. Without scavenger injection, the CO₂ content was ~2.2%, and with the scavenger applied, the CO₂ consistently remained below 2.0%, even though the content of CO₂ varies due to the plunger-assisted lift type of the producing well. The CO₂ scavenger yielded a typical reduction in CO₂ levels of 10% to 15%, easily meeting the maximum allowable content specification. The CO₂ scavenger readily absorbed acid gases, successfully modified the pH, and proved to be water soluble.