Removal of Hydrogen Sulfide and Carbon Dioxide from Injection Water by a Hydrocarbon Gas Cycling Process
- Wallace J. Frank (Humble Oil and Refining Co.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- February 1969
- Document Type
- Journal Paper
- 163 - 166
- 1969. Society of Petroleum Engineers
- 4.1.5 Processing Equipment, 5.4.3 Gas Cycling, 5.4.1 Waterflooding, 4.6 Natural Gas, 4.1.2 Separation and Treating, 3 Production and Well Operations, 4.1.6 Compressors, Engines and Turbines, 4.1.4 Gas Processing, 4.2.3 Materials and Corrosion
- 1 in the last 30 days
- 283 since 2007
- Show more detail
- View rights & permissions
Stripping CO2 and H2S from injection water by cycling sweetened hydrocarbon gas countercurrent to the water flow in a contact tower solved a serious corrosion problem in the Wickett waterflood.
Equipment that must handle water containing relatively large quantities of carbon dioxide and hydrogen sulfide is susceptible to corrosion so excessive that it may not be economically controllable using corrosion inhibitors. One such extreme condition developed in a waterflood where selective injection into multiple zones through common wellbores necessitated annular injection, which eliminated the feasibility of using down-hole protective coatings.
Severe tubing corrosion was observed and continued even after inhibitor treatment had been increased to as much as 72 ppm. This relatively expensive inhibitor program justified removing the corrosive constituents hydrogen sulfide and carbon dioxide. A process developed for this purpose consisted of stripping these gases from the water by cycling sweetened hydrocarbon gas countercurrent to the water flow in a contact tower. This treatment rendered the water quite suitable for use as injection water in bare tubing and casing with the addition of corrosition inhibitor in economical quantities.
From the start, in May, 1963, of the Wickett waterflood in Ward County, Tex., sour El Capitan Reef water mixed with sour produced water has been used for flooding at a rate as high as 40,000 B/D. Although the mixed water was severely corrosive, tests indicated that a prudent inhibitor program could successfully control corrosion in this waterflood. Because the water was injected into 76 injection wells with 175 injection streams, it was necessary to use annular injection to attain selectivity. Corrosion inhibition of the injection waters was highly essential because downhole protective coatings could not be used effectively. Experience using corrosion inhibitors at this flood revealed that corrosion control was not satisfactory even after the inhibitor concentration was increased from 12 to 72 ppm over a period of 2 years. A decision was made to strip the hydrogen sulfide and carbon dioxide from the water by cycling sweetened hydrocarbon gas countercurrent to the waterflow in a contact tower. Since April, 1965, this process has been used to effectively control corrosion process has been used to effectively control corrosion in tubing and casing with the addition of economical amounts of corrosion inhibitor.
Sweetening water at the Wickett plant costs about 4.0 mils/bbl. In plants flaring hydrogen sulfide in volumes economically attractive for conversion to sulfur or its allied products for sale, the net income from this operation will defray water treating costs to some degree. Recovery of the 2 tons/day of sulfur available from the flare at Wickett could be economically attractive at 1968 prices; however, the waterflood is too nearly depleted. Sulfuric acid manufactured from the flare gas could become more economical than using commercially purchased acid.
Corrosion in Wicket Waterflood
The Wickett waterflood began in May, 1963, with injection of 39,000 B/D into 62 injection wells with 175 injection streams.
|File Size||417 KB||Number of Pages||4|