Analysis issues of acidic water after processing high-sulfur crude oil?
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1. After processing high-sulfur crude oil, the acidic water from hydrocracking, hydrorefining, and delayed coking contains high levels of hydrogen sulfide, which poses difficulties for analysis. The main issues are the high concentration of hydrogen sulfide and its strong odor. We plan to analyze the iron ion content and pH value (using colorimetric methods for the iron ion analysis) in order to monitor corrosion levels. I wonder how those facilities that have already processed high-sulfur crude oil handle this situation? Any good suggestions? What is the analysis frequency? What analysis method should be used? 2. Currently, the emulsification of acidic water in coking is quite severe, making it impossible to use sampling and colorimetric analysis for evaluation. How have various units addressed this issue? Why is the emulsification of acidic water in coking so severe? What is the reason? If a demulsifier is used, where should it be added?
I’m not sure why the coking acidic water becomes emulsified; adding a demulsifier works well, and it can be added before it enters the buffer tank.
Previous question: The analysis and monitoring frequency of acidic water in hydrogenation units is usually once a week or once every two weeks, as the H2S concentration in this area is very high, reaching up to 20,000–30,000 PPM or even higher. Frequent sampling and analysis can pose a risk of injury to personnel, but too infrequent monitoring loses its purpose. pH analysis is performed using a pH meter, and no treatment is required for the sample. Iron ion analysis is performed using the potassium thiocyanate spectrophotometric method. The condensate water in the processing media of refineries often contains a high amount of organic substances, iron sulfide, and other corrosion products. The water sample must be oxidized with sulfuric acid and nitric acid before being dissolved in hydrochloric acid; the sample should be in a strongly acidic environment. Tests have shown that the recovery rate for determining the total iron content in the condensate water from refinery processing media using the potassium thiocyanate spectrophotometric method is 97–103%. Repeatability is also good. Second question: Unclear. I will reply after consulting an expert.
First point: For the chemical analysis of the condensate water from hydrogenation and coking units, in addition to iron ions and pH value, it is also necessary to analyze the levels of CN and ammonia; the analysis should generally be carried out 1 to 2 times per week! Using colorimetry for iron ions results in large errors; atomic absorption spectroscopy is the better method. Second point: The problem of acid water emulsification in coking units is related to the properties of the raw materials used in processing; it has little to do with the sulfur content. It is necessary to test the nitrogen content in the crude oil, and it may also be related to corrosion inhibitors, as most of these inhibitors contain small amounts of surfactants (emulsifiers) in order to improve their water solubility. Third point: It is possible to consider adding an demulsifier appropriately, with the demulsifier being added at the outlet of the oil and gas line at the top of the tower!
The selection of the model for coking demulsifiers is very important, as ordinary demulsifiers are not effective. Reverse-phase demulsifiers are generally used. NS-9920 produced by Nanjing Petrochemical performs very well, as it can reduce COD and oil content; it has already been used in multiple delayed coking units.