This document is an expanded abstract.


Inorganic scale associated with conventional hydrocarbon extraction has been well studied over the past 50 years and the mechanisms of formation, inhibition and removal are now well understood within the industry. For enhanced oil recovery (EOR) significant changes occur within the reservoir as a result of injected chemical or changes in fluid type that are used to increase the oil recovery.

In the case of alkali surfactant polymer (ASP) flooding, the current industry understanding of scale prediction models for such systems is discussed, along with the current inhibitor screening tests to qualify scale inhibitors for squeeze application in a Middle East field. The design of the different squeeze treatments applications for treatment of formation water and injection water production are presented.

Geochemical consequences of ASP flooding

A general statement that describes the impact of ASP flooding is the application of low salinity brine to displace oil in reservoirs which typically have formation waters with low salinity also with additional alkalinity, commonly in the form of Na2CO3 at a pH of 10-11.

In the ASP flooded fields, the principle issues with formation of inorganic scale will be within the production wells and topside process. The generation of the ions required to create the silica scales and carbonate scales (CaCO3) occurs close to the injector well and these ions are transported to the production well and proceed to form scales as the conditions change, such as declining temperature (silica scales), declining pressures (carbonate scales).

Laboratory evaluation of squeeze chemical suitability of ASP flooded wells

Inhibitor Performance

Table 1 shows the formation water (FW) and injection water proposed for the ASP flood. 1% Na2CO3 would be added to the IW to create the alkalinity during the flood. This addition of Na2CO3 increased the pH from 7.5 to 11.

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