B41oa oil and Gas Processing Section a flow Assurance Heriot-Watt University

partially inhibited; thus, there may be inhibitor assay issues, or other 
restrictions, on the inhibitors which can be applied downhole or topside. 
2.5.1 Scale Inhibitor Squeeze Treatments 
Scale inhibitor “squeeze” treatments provide one of the most common and 
efficient methods for preventing the formation of sulphate and carbonate 
scales in producer wells. The chosen product(s) must perform the following 
tasks: 
i. 
Prevent or delay sulphate scale formation which will occur when 
injected sea water (containing sulphate ions) mixes with formation 
water (containing barium, calcium and strontium) in the near-wellbore 
region over the production life of a particular field. 

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Appropriate scale inhibitors must perform this task at very low 
concentrations – sometimes referred to at the Threshold Concentration 
(Ct), or the Minimum Inhibitor Concentration (MIC). 
ii. 
Prevent or delay carbonate scale formation which will occur at various 
stages including the production tubulars, topside equipment and in the 
near-wellbore formation area – as discussed, this is as a result of 
pressure reduction during production. Appropriate scale inhibitors must 
perform this task at very low concentrations (Ct or MIC). 
iii. 
Interact with reservoir substrates in order to give long inhibitor return 
profiles at or above the Ct (or MIC) level. 
Thus, it is not sufficient that a particular species inhibits scale 
effectively, but it must also interact appropriately within the formation 
so as to provide long squeeze lifetimes. 
iv. 
In addition to these properties, the selected squeeze treatment 
chemical should be relatively stable to thermal degradation, under 
downhole conditions, and compatible
 
with the particular brine system. 
Brine compatibility is a major issue of concern, since premature 
precipitation of inhibitor complexes during injection may lead to the 
formation of a pseudo-scale with associated fines plugging. 
Furthermore, when other treatment chemicals are applied with the 
scale inhibitor, or remain in the near-wellbore area following 
application, then compatibility of the applied scale inhibitor (with these 
other treatment chemicals) must be addressed. 
Two types of inhibitor squeeze treatment are routinely carried out where the 
intention is either: one, to adsorb the inhibitor by a physico-chemical process; 
or two, to extend the squeeze lifetime by precipitation (or phase separation). 
This latter scenario is commonly carried out by adjusting the chemistry (
+
2
Ca
ion concentration, pH, temperature) of the polymeric and the phosphonate 
inhibitor solutions. 

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A schematic of a field squeeze treatment is shown in Figure 7 below: 
Figure 7: Typical Scale Inhibitor Squeeze Treatment 
E N 
The procedure for applying a squeeze treatment normally involves the 
following six stages: 
1. A “spearhead” package (a demulsifier and/or a surfactant) is injected 
which is thought to increase the water wetness of the formation and/or 
improve injectivity. 
2. A dilute inhibitor preflush is often applied to push the spearhead into 
the formation and, in some cases to cool the near wellbore region. 
3. The main scale inhibitor treatment is injected which contains the 
inhibitor chemical, normally in the concentration range 2.5% to 20%. 
4. A brine overflush is applied which is designed to push the main 
treatment to the desired depth in the formation away from the wellbore. 
5. A shut-in or soak period (usually about 6 - 24 hours) is allowed which is 
the time needed for the inhibitor to adsorb (phosphonate/polymers) or 
precipitate (polymers) onto the rock substrate. 
6. Finally, the well is brought back into production. 
Several chemical and physical processes, in these steps of a scale inhibitor 
squeeze treatment, may affect the inhibitor adsorption and phase separation 
characteristics. In addition, these same factors may be responsible for various 
types of damage in the reservoir formation. 
Adsorption of scale inhibitors is thought to occur through electrostatic and van 
der Waals interactions between the inhibitor and formation minerals. 

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This interaction may be described by an adsorption isotherm 
(C)
Γ
, which is a 
function of pH, temperature, mineral substrate and involves cations such as 
+
2
Ca
(Vetter, 1973; King, 1989; Pardue, 1991; Meyers, 1985; Przybylinski, 
1989; Yuan, 1993; Kan, 1991; Kan, 1992; Sorbie, 1993a; Sorbie, 1993b; 
Breen, 1991; Graham, 1994). 
The precise form of 
(C)
Γ
determines the squeeze lifetime, as has been 
described in detail in a number of previous papers (Sorbie, 1991a; Sorbie 
1991b; Sorbie, 1992; Hong, 1987; Yuan, 1992). 
The “precipitation squeeze” process is based on the formation of an 
inhibitor/calcium salt, usually of phosphino-polycarboxylic acid (PPCA) or 
polyacrylic acid (PAA) scale inhibitor, within the formation. The process almost 
certainly goes through an adsorption stage then a phase separation which is 
controlled either by temperature and/or pH (Carlberg, 1983; Carlberg, 1987; 
Olsen, 1992; Wat, 1993). 
The level of inhibitor in the return curve is then thought to be governed by the 
solubility of the inhibitor/calcium complex and the rate of release of inhibitor 
into the produced water. 
In high salinity brines, in particular those containing high levels of calcium 
cations, fears of reservoir engineers (with respect to premature precipitation of 
the injected phosphonate or polyacrylate-based inhibitor) have often led to 
their de-selection on compatibility grounds. However, in many cases, such 
incompatibility aspects may be overcome with appropriate application 
strategies using combinations of pre-flushes and chelating agents.