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With the current trend for application of Enhanced Oil Recovery (EOR) technologies, there has been much research into the possible upsets to production, from the nature of the produced fluids to changes in the scaling regime. The key question being addressed in this publication is the influence of EOR chemicals, such as hydrolyzed polyacrylamide (HPAM), on scale inhibitor (SI) squeeze lifetime for barium sulphate and calcium carbonate scale risk. Squeeze lifetime is defined as the duration of time (or produced water volume) before the minimum inhibitor concentration (MIC) is reached. This is controlled by the adsorption, and later release, of the inhibitor onto the reservoir rock and the MIC of the inhibitor selected for the produced brine. This paper builds on earlier published work investigating potential changes to inhibitor adsorption caused by polymer EOR produced and moves to the evaluation of the changes in MIC due to the presence of EOR chemical. In the static inhibitor performance bottle tests, the EOR polymer alone appeared to show some degree of inhibition performance against BaSO4, but below a level required for effective scale management. However, in combination with the inhibitor (DETPMP) at near MIC levels, the inhibition efficiency was negatively impacted by the presence of degraded HPAM EOR polymer. During dynamic tube blocking tests, the inclusion of even low levels of HPAM (2.5 ppm) were shown to reduce the differential pressure build up suggesting barite scale inhibition or reduced adhesion to the coil. Furthermore, the scale morphology produced in these tests, examined under a scanning electron microscope, was clearly impacted in the presence of HPAM. For the CaCO3 system there appears to be increasing positive impact from HPAM on CaCO3 morphology with HPAM concentration and, as observed for BaSO4, an improved performance in dynamic efficiency experiments. However, at higher HPAM concentrations (500 ppm) the precipitate was amorphous and only a minor pressure rise was observed during the tube blocking experiments. From these observations, it is clear that HPAM can impact the way both calcite and barite scale grow, especially at lower inhibitor concentrations ( This study represents a comprehensive review of both inhibition performance in the presence of an EOR polymer and with these findings the implication to field treatment lifetimes and associated costs of scale management via scale squeeze in a field under HPAM flooding.

With the current trend for application of Enhanced Oil Recovery (EOR) technologies, there has been much research into the possible upsets to production, from the nature of the produced fluids to changes in the scaling regime. One key question that is yet to be addressed is the influence of EOR chemicals, such as hydrolysed polyacrylamide (HPAM), on scale inhibitor (SI) squeeze lifetime. Squeeze lifetime is defined by the adsorption of the inhibitor onto the reservoir rock, hence any chemical that interacts with the adsorption process will have an impact on the squeeze lifetime. This paper experimentally demonstrates potential changes to inhibitor adsorption from a polymer EOR project by demonstrating the complex interactions between HPAM and phosphonate scale inhibitors with respect to adsorption. This work presents a detailed coreflooding programme, supplemented with bottle tests, to identify the impact of HPAM on a diethylenetriamine penta(methylene phosphonic acid) (DETPMP) squeeze lifetime. A range of pH values, representing the expected inhibitor injection pH, have been studied on consolidated and crushed Bentheimer sandstone. A temperature of 70°C is used throughout as it represents the likely maximum temperature at which HPAM would be applied and the typical temperature at which DETPMP would be used in squeeze applications. The results presented show that scale inhibitor application pH is key in defining the impact of HPAM on DETPMP adsorption. Neutral pH displays a reduced squeeze lifetime, believed to be due to reduction of adsorption sites by HPAM. However, this impact could be countered by injecting this type of scale inhibitor at a low pH (e.g. pH 2). Static tests performed alongside the corefloods show that even low inhibitor concentrations (as found in SI pre-flushes) are sufficiently acidic to fully precipitate the HPAM from solution, but did not impact the adsorption. This study suggests, contrary to the commonly held view in the industry that EOR polymers may negatively impact squeeze lifetime, that with the correct selection of inhibitor type and their application pH it is possible to achieve the same results as in a conventional reservoir.

In fields where it is unattractive to control barite scaling through chemical intervention (e.g. scale inhibitor squeeze treatments), one option is to substitute the injection of seawater with low-sulphate seawater (LSSW) for pressure maintenance. Injecting LSSW minimises the operational risk of barite deposition on injection water breakthrough. The specification for the LSSW sulphate ion concentration dictates the design of the Sulphate Removal Plant (SRP) required and may influence the field development strategy. There is the possibility that barite deposition can occur within gravel packs designed to minimise sand production. It is in these that the potential for scaling was investigated. Dynamic scaling runs were performed in laboratory scale gravel packs using a mixture of a Formation Water (FW) and LSSW. The initial design involved varying the total flow rates and mixing ratio of the brines in order to produce a 'safe envelope' (Ba2+/SO42- composition) that could be used in the field. The experimental procedure was developed to examine the steady-state effluent profiles and to use these to derive the rate constant, k, for barite deposition. This could then be used in a computer model to predict scaling quantities and timescales. Under 'true' LSSW conditions (20ppm sulphate) the steady-state effluent results proved difficult to interpret due to the limits of accuracy. The sulphate levels were then varied in order to increase the level of accuracy, with the hypothesis that, for a given set of conditions (temperature and pressure), the rate "constant" should remain the same for any Saturation Ratio (SR). Upon closer inspection of the derived rate constants, it was discovered that they were not constant but were directly proportional to the SR for the different input concentrations. Plotting the rate constants against SR showed a linear relationship between the two variables. This was confirmed by using sulphate and barium levels that were unrelated to the previous series of tests. The experimental procedure and the resulting model being developed from the work reported in this paper will assist in designing operational procedures to minimise rate related scaling in gravel packs in fields where squeezing is undesirable.

In recent years, a number of non-aqueous delivery systems for scale inhibitors (SI) have been developed which are designed to be applied as low damage, low watercut or pre-emptive squeeze treatments, e.g. in critical or expensive subsea wells. The mechanisms through which non-aqueous scale inhibitor systems operate is an important technical issue. Only when a good understanding of the transport and retention mechanisms is developed, can this be built into a model for designing such squeeze treatments (such as the SQUEEZE VI model). The experimental work in this paper focused on a specific "oil soluble" version of a standard penta phosphonate inhibitor (DETPMP), which has been described previously in the literature. Several floods have been carried out comparing corresponding non-aqueous and aqueous applications of DETPMP in order to better determine the main features of the transport and retention mechanism of the system. Novel core flood experiments with tracers in both the aqueous and oleic phases have been performed and are reported in this paper. Unique information is generated by designing very detailed flooding cycles and carrying out tracer floods at each stage. Results point to the formation of an immobile "emulsion like" third phase in this system. In order to confirm our proposed mechanism, non-aqueous inhibitor has also been applied at zero residual water saturation (100% oil) to investigate whether or not the tailing effect (or third layer deposition) could be generated without prior oil/water partitioning of the scale inhibitor. For this case, tailing of the brine tracer only was observed. Mass balance showed that there was still considerable retention of scale inhibitor that was ultimately produced during the aqueous post-flush. The corresponding aqueous inhibitor coreflood showed similar returns to that of the previous non-aqueous experiment and no retardation of either the tracer species or the metal ions in the brine. No formation damage occurred for either phase after the inhibitor was injected. A further control flood (no SI treatment) proved that the brine tracer tailing arose as a direct result of the treatment. The use of the tracer species in each (water and oil) phase is a genuine innovation, which provides a powerful additional technique for demonstrating the effect of chemical treatments on the flow and the retention of all fluids in the core.

One proposed method for the chemical control of produced water is by using a "relative permeability modifier" (RPM) which is usually based on a water soluble polymer. A considerable amount of literature on such materials has appeared although there is still not a complete consensus on the actual mechanism through which RPMs operate within a porous medium. One mechanism that has been suggested is based on the existence of an adsorbed polymer layer where this layer, within a water-wet porous medium, reduces water flow more significantly than oil. In this paper, we propose further developments of this adsorption mechanism of relative permeability modification. The present study is based on two complementary approaches as follows: (i) a series of detailed coreflood experiments has been performed to assess the impact that an adsorbed polymer layer has on the fluid flow pathways. Experimental results on tracer pulses, end point relative permeabilities/saturations and pressure profiles have been utilised in our analysis; (ii) a pore-scale network model has been developed which incorporates the proposed mechanism of RPM operation. The predictions from this model have then been compared with the experimental results. It has been possible to deduce that, not only is water flow affected more significantly than oil, but that the manner in which this occurs is different for each phase. The contributions to both the water and oil conductivity of relative permeability effects (due to saturation changes) and actual "pore blocking" is deduced.