Calcium carbonate scale was detected in several vertical wells in a sandstone reservoir in Saudi Arabia. The scale was detected downhole, plugging gravel packing screens and the intake of submersible pumps. Scale build up caused significant decline in oil production from this field. The sandstone reservoir is water-sensitive and has a bottom hole temperature of 160°F.
An emulsified scale inhibitor (phosphonate-type) treatment was designed to mitigate scale in this field. Recently, Nasr-El-Din et al.1 discussed the development of this new treatment and reported initial field results. So far the treatment was successfully applied in more than twenty wells. Some of these wells were de-scaled before the treatment, while other wells were treated before scale detection.
The objectives of the present paper are to assess the outcome of this treatment based on field data and to optimize the scale squeeze treatment based on the analysis of well flow back samples. Samples of produced water from these wells were collected and analyzed for nearly three years.
The scale treatment was successfully conducted in more than twenty wells with various water cuts. No scale was detected in any of the treated wells for nearly three years. No significant decline in oil production was observed. Based on field data, it is known that the treatment lifetime is greater than two years and is estimated to be 3–4 years.
This paper describes fieldwork done to optimize the performance of a novel emulsified scale squeeze treatment in a sandstone reservoir. It also discusses the importance of well flow back analysis and how it can be used to enhance the outcome of a scale squeeze treatment. The emulsified chemical was successful in meeting the main objective of the treatment, i.e., providing scale mitigation for greater than three years, while maintaining the integrity of the formation.
The concentration of total phosphorus ion in the well flow back samples was found to decline with time (a straight line on a log-log scale). This is the first set of field data (twenty wells) that shows this linear relationship following an emulsified scale squeeze treatment.
The slope of this linear relationship was found to be independent of well location, length of target zone, initial water cut and oil production rate.
Analysis of flow back samples indicated the emulsified scale inhibitor behaved as expected and more than 80% of the injected inhibitor was retained in the formation.