It is can be readily demonstrated that hydrogen sulfide (H2S) and carbon dioxide (CO2) partial pressure can be estimated based upon formation temperature for hot (>275ºF), high pressure, high temperature (HPHT) clastic reservoirs. This knowledge is extremely useful in the practice of sour service materials selection and materials qualification.

In fact for H2S, for early, untested wells in a field development program, it is recommended that these geochemical projections be used even if downhole sample analysis results are less than the projection. Even minor errors in H2S parts per million (ppm) due to filtrate, sample process, or analytical scavenging may lead to significant errors in equipment materials selection. The sensitivity to these H2S sampling errors is especially critical in the temperature range of 300-380ºF.

Likewise, CO2 can also be estimated, and the results of these two correlations can be used for pH prediction of downhole conditions. The resultant projected gas acidity and pH is then useful in ISO 15156/NACE MR01751  materials qualification work and corrosion control planning

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