Summary

Issues such as high corrosion rate, hydrogen sulfide (or H2S) generation, and scale reprecipitation have required the use of alternative dissolvers such as tetrakis(hydroxymethyl)phosphonium sulfate (THPS)–ammonium chloride (or NH4Cl) blend and chelating agents to dissolve iron sulfide (or FeS) scales. However, there are many aspects of these dissolvers that need investigation. This paper provides a guideline to select the best dissolver under various oilfield conditions by an extensive laboratory study. Furthermore, the iron sulfide scale removal is enhanced by the use of new synergists to the chelating agents.

The application of THPS and diethylenetriaminepentaacetic acid (DTPA) in well tubulars or pipelines requires laboratory testing to determine the optimal conditions such as dissolver concentration, treatment time, and dissolver/scale (D/S) ratio (cm3/g) at 150°F. This evaluation considers oil-wet scales, mixed scales, presence of additives, and presence of salts during the treatment. Synergists such as potassium chloride (or KCl), potassium iodide (or KI), potassium formate (or HCOOK), sodium fluoride (or NaF), and potassium citrate (or K-Citrate) were added to ethylenediaminetetraacetic acid (EDTA), DTPA, and hydroxyethylethylenediaminetriacetic acid (HEDTA), and the scale solubility was evaluated at 150 and 300°F. Inductively coupled plasma–optical emission spectrometer analysis of the supernatant solution at various intervals of time up to 48 hours revealed the kinetics of the dissolution process. H2S generated from the scale dissolution process was measured using Draeger tubes. Corrosion tests helped in measuring the damage to the tubulars as a result of the dissolver’s contact with N-80coupons.

Solubility tests indicated the dissolver’s scale removal capacity at different concentrations. The work also accounted for the consumption of the dissolver for the scale removal. The optimal blend was chosen considering both the dissolution capacity and the dissolver consumption. For THPS–ammonium chloride blend, 0.75 mol/L THPS (30 wt%) and 2 mol/L NH4Cl (10 wt%) proved to be the optimum dissolver concentration at 150°F. Similarly, for DTPA, 0.4 mol/L K2-DTPA was evaluated to be the most effective dissolver concentration. The THPS–ammonium chloride blend was found to dissolve the iron sulfide slowly compared with K2-DTPA and 15% hydrochloric acid (HCl). The presence of crude oil on the scale hindered its solubility with K2-DTPA by 8%. The presence of calcium carbonate influenced higher selectivity of chelating the calcium ions by K2-DTPA. However, the overall fraction of scale removal was not affected. Adding corrosion inhibitors (CIs) did not affect the scale solubility significantly and also helped in maintaining an acceptable corrosion rate of N-80 coupons below 0.05 lb/ft2 at 150°F. The reaction of HCl and the iron sulfide scale generated 1,800 ppm of H2S in comparison with 0- and 10-ppm by THPS–ammonium chloride blend and K2-DTPA, respectively. Adding potassium iodide and potassium citrate to EDTA helped in improving the scale solubility at 150°F. Sodium fluoride improved the scale dissolution by EDTA and DTPA at 300°F.

This paper addresses oilfield-like conditions on scale solubility by evaluating the role of mixed scale, scale mass, presence of hydrocarbons on the scale, and presence of monovalent/divalent ions in dissolver solution. A detailed and direct comparison of HCl, THPS–ammonium chloride blend, and DTPA in dissolving iron sulfide at various conditions enables easier selection of the dissolver for a field treatment. New synergists for iron sulfide scale dissolution are introduced in this paper. This work can help oilfield companies understand the nuances of applying different alternative iron sulfide dissolvers.

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