Sand production in unconsolidated reservoirs has been an ongoing issue leading to significant reduction in well productivity, costly remediation, and damage to production facilities. This pape r introduces two novel chemical-based technologies, one water and one oil-soluble, that were designed to reduce operational complexities, improve reliability, extend ESP run life and offer critical benefits such as reduced relative permeability to water with minimal impacts on oil production. These technologies can be applied in wide range of reservoir conditions, from low (down to 15 °C) to high temperature (up to 110 °C) and can be deployed for both vertical and horizontal wells. In this study, a novel protocol and apparatus for sand migration study was developed. Sand packs with different sand sizes (100, 60 and 40 meshes) were prepared and tested under different pressure gradients to simulate various downhole environments. The impacts of water composition and temperature were also explored. The sand consolidation performance was quantified based on amounts of sand produced with and without treatment in conjunction with pressure drop profiles. The set up was then modified to measure effective permeability after chemical treatment. More than one hundred field trials were conducted using the oil-soluble technology to validate the laboratory findings. The laboratory results demonstrate that both oil and water-soluble technologies are effective in reducing sand production significantly. Performance of the water-soluble technology is a function of additive concentration and temperature; higher temperature environments require higher concentrations of the chemical additives. On the contrary, the oil-soluble technology is relatively insensitive to temperature variation and thus consolidation efficacy remains constantly high within the applicable range. Most importantly, both technologies significantly reduced water mobility (> 50%) in which the oil mobility reduction was merely less than 10%. The success rate of the oil-soluble technology is greater than 90% based on field result (>100 field trials) including low temperature reservoirs and selected sections of long horizontal wells. It is important to note that the oil-soluble technology, once pumped and set downhole, is no longer oil soluble therefore has been successfully deployed in oil reservoirs. This technology has also been shown to significantly reduce the maintenance frequency of electrical submersible pumps (ESP) and thus significantly extended run lives are observed. In certain cases, the frequency of cleaning out sand was reduced from several days to more than one year. Field observations also indicate that oil production rates were increased (>15%) and sustained for 2-3 months. The results of this study provide helpful information on using chemical-based technologies to address sand production issues in a wide range of reservoir temperatures with a high success rate. The novel technologies introduced here not only are effective for sand consolidation and extended ESP run life, but also efficient as relative permeability modifiers.

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 (<MIC) and hence impacts the mechanism by which DETPMP can function to prevent scale nucleation and growth. 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.

Abstract 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.

Summary In recent years, a number of nonaqueous delivery systems for scale inhibitors (SI) have been developed that are designed to be applied as low-damage, low-water-cut or pre-emptive squeeze treatments (e.g., in critical or expensive subsea wells). The mechanisms through which nonaqueous SI 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 pentaphos-phonate inhibitor (DETPMP), which has been described previously in the literature. Several floods have been carried out comparing corresponding nonaqueous and aqueous applications of DETPMP 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. To confirm our proposed mechanism, nonaqueous 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 previous oil/water partitioning of the SI. For this case, tailing of the brine tracer only was observed. Mass balance showed that there was still considerable retention of SI that was ultimately produced during the aqueous post-flush. The corresponding aqueous-inhibitor coreflood showed similar returns to that of the previous nonaqueous 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.

Abstract 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.