Scale inhibitors are routinely injected into the near wellbore formation in "squeeze" treatments in order to prevent the buildup of mineral scale. The inhibitor must then interact with the formation such that it is retained and returns over a suitably long period of time (3 - 18 months) at a concentration above the threshold level, Ct. However, the introduction of a high concentration (2.5 to 20% solution) scale inhibitor slug, which is usually of low pH (2 to 4.5), along with the associated seawater overflush into the near well-bore region has the potential to cause formation damage. This damage may result from the dissolution of authigenic cements (carbonate and clay) which may lead to sand production, fines migration and the precipitation of iron carbonates and oxy-hydroxide gels. In order to minimise this risk and to correctly select both chemicals and operational strategy, the interaction between injection fluids, formation minerals and pore fluids must be adequately understood.
The main objective of this paper is to investigate how geochemical modelling can help us to analyse and predict the consequences of applying low pH inhibitor packages in field core of known mineralogy. This field example is chosen from a large database of reservoir condition corefloods which has been assembled at this laboratory. The modelling results for pack floods using the mineral separates (calcite and K-feldspar) are first presented before describing the results for the core flood. It has been found that the geochemical model cannot be applied without some careful consideration of the gross kinetics of certain thermodynamically favourable reactions. For example, dolomite is predicted when magnesium ions are present in the flooding brine and calcite is contained in the core. In practice, however, this is not observed and the reaction must be suppressed when considering production time scales. In addition, the effects of the inhibitor, which is itself a weak polybasic acid (H10A in the case of DETPMP), must be taken into account. Here, this is dealt with empirically since the entire range of pKa values and calcium binding constants for the inhibitor were not known. A number of preliminary conclusions are presented on the utility and applicability of geochemical modelling to inhibitor package/rock interactions.
The application of scale inhibitor "squeeze" treatments is the most commonly applied remedy for the prevention of downhole carbonate and sulphate mineral scale deposition. In this process, typically a low pH slug of inhibitor is injected into the near wellbore formation followed by an overflush of non-formation brine which may be a fresh water in on-land fields and is usually seawater in offshore fields. The whole package is shut-in after injection to allow inhibitor adsorption or precipitation - depending on the designed mechanism of retention - to occur to its full extent. However, in addition to remedying the scaling problem, such low pH packages may have some potential for formation and fluid damage in the near wellbore formation. For example, if the dissolution of carbonate minerals occurs, this can in turn lead to changes in the composition of brine which may affect inhibitor performance. The designed application may switch from an adsorption to a precipitation inhibitor squeeze mechanism thus making the treatment non-optimal. In addition, if carbonate is a principal cement within the formation, then other related problems may occur such as fines migration, sand production and wellbore instability. Other geochemical reactions such as feldspar pitting and clay swelling may also occur. This type of formation damage is usually detected by carrying out a reservoir condition core flood using the field core which has been "appropriately" conditioned and then treated with the scale inhibitor chemicals. Many examples of such floods have been reported by this group.