Black tar-like fouling material was driving frequent shut-downs and increasing corrosion in the inlet area of a gas plant that processes lean gas with high acid gas content (68%CH4, 20%CO2 and 12%H2S). Analytical work indicated that the nitrogen containing corrosion inhibitor (CI) polymerized with sulfur compounds (polysulfides, elemental sulfur and/or H2S) in a type of a vulcanization process resulting in a hard-to-clean insoluble fouling product. Corrosion testing confirmed the role of the CI in creating this fouling. A customized autoclave testing was designed to include powdered elemental sulfur circulating in the bulk fluid. This allowed for a recreation of the condition in the plant where solid elemental sulfur comes out of solution and fouling occurs. The tests reproduced the tar-like fouling substance in the presence of the incumbent corrosion inhibitor. The data showed that a surfactant (wetting agent) used to keep elemental sulfur from depositing would also protect the steel from elemental sulfur corrosion. Other CIs were tested, but none provided protection at an acceptable dosage level without forming this foulant material.


Black tar-like fouling, as seen in Figure 1, in an inlet area heat exchanger would drive shut-down for a gas plant processing highly sour gas consisting mainly of methane (68%) with the balance being acid gases (12% H2S and 20%CO2) and trace compounds. Condensed water is produced throughout the field, while formation water is only produced in part of the field. No liquid hydrocarbons are produced. Besides sales gas, the plant produces elemental sulfur and CO2.

The Inlet Area separates the gas and the water, with some of the water being cooled down for recirculation to the front of the inlet area to help cool the production stream before the gas is processed through a AGRII unit in the Process Area. There are two inlet areas, one for Trains 1&2 and another one for Train 3. The produced water in Train 3 is solely water that has condensed out of the gas, and is therefore low in salinity (100ppm TDS, 120ppm bicarbonate). In contrast, the water in Trains 1&2 includes formation water and the salinity is 20,000ppm TDS and 2,300ppm bicarbonate. The water chemistry for this two water types is further described in Table 1 with the pH representing a degassed sample. Calculated pH at pressure and temperature at the sample location was pH5.7 for Train1&2 and pH4.7 for Train 3. The lower pH in Train 3 is explained with the lower bicarbonate value.

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