Removal of Wellbore Scales from High Temperature Depleted Gas Wells

Abstract Mixed mineral scales were observed in production tubulars of many Mobile Bay gas wells. These wells are mostly ultra-high temperature (about 400oF) sour gas producers with condensed formation water. Reservoir pressure (about 5000psi) is considered low for the 21,000 ft deep wells due to depletion. Hydrochloric and organic acids have been used historically for scale removal in these wells with mixed results. Scale analysis of the samples retrieved from these wells confirmed the presence of salts and mineral scales. Six commercial treatment products were evaluated kinetically and thermodynamically for their dissolution efficiency on these field scale samples. One product with non-acid nature was identified to be the best to dissolve the scales efficiently with minimum operational risks of scale re-precipitation, corrosion of tubulars, and potential formation damage. Treatment candidate wells were analyzed based on well performance evaluation. Three wells with skins significantly higher than expected due to scale formation in the production systems, were selected as treatment candidates. These wells were treated with the nitrified non-acid system to dissolve the skin damage. Treatments are considered successful with an additional gas production gain of 1,867 BEQ/day. The paper discusses the laboratory evaluation and field validation of the non-acid operationally simple system for the scale removal. Introduction The Fairway Field is located in the Gulf of Mexico, four miles south of Dauphin Island, Alabama, and 17 miles southeast of the sour gas processing Yellowhammer plant 1,2. The Yellowhammer Plant and the Fairway Field, together make Shell's Mobile Bay Operations as illustrated in Figure 1. In 1991, first production of natural gas began from Norphlet formation of Fairway discovery from depths between 21,000 and 22,000 ft. The reservoir temperature and effective stress are about 400 oF and 70 MPa, respectively. Four Mobile Bay wells were selected to be the candidates for matrix acidizing treatment because of their low production. The low production was suspected to be due to the formation damage caused by the scale build up possibly in the tubing and around the perforations. The scales were not quantitatively analyzed before the matrix acidizing due to the unavailability of the scale sample. However, historical well data indicate that the type of the scale should be suspected as a mixture of metal sulfides, calcium carbonate, and barium sulfate. Many hydrochloric acid jobs have been carried out on these candidate wells, but production generally decreased after treatment. Most recently, a pickling treatment followed by matrix acidizing was carried out with a chelant-based organic acid; this particular acid was selected considering the nature of the scale, corrosion inhibition rate at high temperature and minimum re-precipitation of the scale. After pickling the production tubing, the scale collected consisted mainly of Ni3S4, NiS and chromium compounds. This type of scale comes from the interaction of hydrogen sulfide and the tubing materials. After acidizing, the scale collected was analyzed to contain mainly the tubing materials and FeS2 and BaSO4. Even though post treatment production increased by 1.2 MMSCF with less draw-down compared prior to the acid treatment, the production decreased to the same rate as before in one week. The skin was not changed. This may be due to the facts that the acidizing treatment cannot dissolve the scale components such as BaSO4 and FeS2, and the wellbore is not completely clean, possibly around the perforations.