Dissolver technology has been developed and applied with varying degrees of success over the past few years to clean carbonate and the more challenging sulphate/sulphide scales from production tubing and process equipment. As HP/HT fields are developed a common remediation approach is one of chemical dissolvers as they appear to be a less costly option than well interventions especially in the new generation of HP/HT fields that are being developed in deep water basins. The challenge raised by these fields is do dissolvers work as well as would be expected at elevated temperature and pressureA set of experiments were conducted at a range of temperatures (80 to 170C) and pressures from vapor pressure at 80C to 3000 psi at 170C to review the impact of temperature (and to some extent pressure) on three dissolvers.This paper shows that at elevated temperature the classic alkali sulphate dissolver (DTPA) dissolution performance declines significantly at 170C. Organic acid dissolution of carbonate appears to be uneffects by the increase in temperature and the dissolution rates increase as would be expected. The novel neutral chelant (GDLA) showed a decline in calcite dissolution performance during the 170C test but unlike the alkali chelant used for sulphate scale this chelant showed degradation after thermal ageing and re testing at 80C.These initial finding suggest that there was temperature limit above which removal of sulphate scales may not be feasible due to re precipitation of a secondary reaction product and for carbonate the current neutral chelants for carbonate removal have a thermal stability issue at 170C.To investigate if such temperature would in fact still be present during an application to a production well modelling work using OLGA and SQUEEZE software packages were conducted. The OLGA software was used to model the cooling effects on the tubing and the potential fluid heating during the 12 hour soak period. The SQUEEZE software used output from OLGA simulation to calculate the fluid temperature within the near wellbore and subsequent changes in temperature during the soak period within the reservoir were able to be assessed. The results for this work confirm that significant cool would occur such as the HT conditions would not be present during a dissolver application event in wells with a downhole temperature of 175 prior to chemical injection. These finding bridge the gap between published field data that shows DTPA and GDLA working at temperatures where our published laboratory testing say it not stable.These are significant findings when evaluating HP/HT chemical cleaning program feasibility for HP/HT fields.

Key words: Downloadable, High Temperature, carbonate scale, sulphate scale, dissolvers, thermal stability.