Immiscible viscous fingering in porous media occurs when a low viscosity fluid displaces a significantly more viscous, immiscible resident fluid; for example, the displacement of a higher viscosity oil with water (where μo >  > μw). Classically, this is a significant issue during oil recovery processes, where water is injected into the reservoir to provide pressure support and to drive the oil production. In moderate/heavy oil, this leads to the formation of strong water fingers, bypassed oil and high/early water production. Polymer flooding, where the injected water is viscosified through addition of high molecular weight polymers, has often been applied to reduce the viscosity contrast between the two immiscible fluids. In recent years, there has been significant development in the understanding of both the mechanism by which polymer flooding improves viscous oil recovery, as well as in the methodologies available to directly simulate such processes. One key advance in modelling the correct mechanism of polymer oil recovery in viscous oils has been the development of a method to accurately model the “simple” two-phase immiscible fingering (Sorbie in Transp Porous Media 135:331–359, 2020). This was achieved by first choosing the correct fractional flow and then deriving the maximum mobility relative permeability functions from this. It has been proposed that central to the polymer oil recovery is a fingering/viscous crossflow mechanism, and a summary of this is given in this paper. This work seeks to validate the proposed immiscible fingering/viscous crossflow mechanism experimentally for a moderately viscous oil (μo = 84 mPa.s at 31 °C; μw = 0.81 mPa.s; thus, (μo/μw) ~ 104) by performing a series of carefully monitored core floods. The results from these experiments are simulated directly to establish the potential of our modified simulation approach to capture the process (Sorbie, et al., 2020). Both secondary and tertiary polymer flooding experiments are presented and compared with the waterflood baselines, which have been established for each core system. The oil production, water cut and differential pressure are then matched directly using a commercial numerical reservoir simulator, but using our new “fractional flow” derived relative permeabilities. The use of polymer flooding, even when applied at a high water cut (80% after 0.5 PV of water injection), showed a significant impact on recovery; bringing the recovery significantly forward in time for both tertiary and secondary polymer injection modes—a further 13–16% OOIP. Each flood was then directly matched in the simulator with excellent agreement in all experimental cases. The simulations allowed a quantitative visualisation of the immiscible finger propagation from both water injection and the banking of connate water during polymer flooding. Evidence of a strong oil bank forming in front of the tertiary polymer slug was also observed, in line with the proposed viscous crossflow mechanism. This work provides validation of both polymer flooding’s viscous crossflow mechanism and the direct simulation methodology proposed by Sorbie et al. (Transp Porous Media 135:331–359, 2020). The experimental results show the significant potential for both secondary and tertiary polymer flooding in moderate/heavy oil reservoirs.

Polymer flooding is a mature EOR technology that has seen an increasing interest over the past decade. Co-polymers of Acrylamide (AMD) and Acrylic Acid (AA) have been the most prominent chemicals to be applied, whereas sulfonated polymers containing 2-Acrylamido-tertiary-butyl sulfonic acid (ATBS) have been used for higher temperature and/or salinity conditions. The objective of this study was to generate guidelines to aid in the selection of appropriate polyacrylamide chemistry for each field case. Our main focus was in sandstone fields operating at the upper end of AMD-AA temperature tolerance, where it needs to be decided whether sulfonation is required. The performance of the polymer throughout the whole residence time in the reservoir was considered since the macromolecule can undergo some changes over this period. Several key properties of nine distinct polymer species were investigated. The polymers consisted of AMD-AA co-polymers, AMD-ATBS co-polymers and AMD-AA-ATBS ter-polymers. The polymers were studied both in their original state as they would be during the injection (initial viscosity, initial adsorption and in-situ rheology) as well as in the state which they are expected to be in after the polymer has aged in the reservoir (i.e. in a different state of hydrolysis and corresponding viscosity retention and adsorption after ageing for various time periods). We note that the combination of viscosity retention and adsorption during the in-situ ageing process has not been typically investigated in previous literature, and this is a key novel feature of this work. Each of the above parameters has an impact on the effectiveness and the economic efficiency of a polymer flooding project. The content of ATBS was limited to 15 mol%. Buff Berea sandstone was applied in the static and dynamic adsorption experiments. The majority of the work was carried out in seawater at temperature, T = 58°C. Under these conditions AMD-AA samples showed maximum viscosity and lowest adsorption when the content of AA was moderate (20 mol%). When the AMD-AA polymers were aged at elevated temperature, the AA content steadily increased due to hydrolysis reactions. When the AA content was 30 mol% or higher, the viscosity started to decrease, and adsorption started to increase as the polymer was aged further. Thermal stability improved when ATBS was included in the polymer structure. In addition, sulfonated polyacrylamide samples showed increasing initial viscosity yields and decreasing initial adsorption with increasing ATBS content. For most of the samples, the maximum observed apparent in-situ viscosity increased when the bulk viscosity and relaxation time of the sample solution increased. The information generated in this study can be used to aid in the selection of the most optimal polyacrylamide chemistry for sandstone fields operating with moderate/high salinity brines at the upper end of AMD-AA temperature tolerance.

Summary Polymer flooding is a mature enhanced oil recovery (EOR) technology that has seen increasing interest over the past decade. Copolymers of acrylamide (AMD) and acrylic acid (AA) have been the most prominent chemicals to be applied, whereas sulfonated polymers containing 2-acrylamido-tertiary-butyl sulfonic acid (ATBS) have been used for higher temperature and/or salinity conditions. The objective of this study was to generate guidelines to aid in the selection of appropriate polyacrylamide chemistry for each field case. Our focus was in sandstone fields operating at the upper end of AA-AMD temperature tolerance, where there is a decision as to whether sulfonation is required. The performance of the polymer throughout the whole residence time in the reservoir was considered because the macromolecule can undergo some changes over this period. Several key properties of nine distinct polymer species were investigated. The polymers consisted of AA-AMD copolymers, AMD-ATBS copolymers, and AMD-AA-ATBS terpolymers (up to 15 mol% ATBS). The polymer solutions were studied both in their original state as they would be during the injection (initial viscosity, initial adsorption, and in-situ rheology), as well as in the state in which they are expected to be after the polymer has aged in the reservoir (i.e., in a different state of hydrolysis with corresponding changes in viscosity retention and adsorption after aging for various time periods). We note that the combination of viscosity retention and adsorption during the in-situ aging process has not been typically investigated in previous literature, and this is a key novel feature of this work. Each of the above parameters has an impact on the effectiveness and the economic efficiency of a polymer flooding project. The majority of the work was carried out in seawater (SW) at a temperature of 58°C. Under these conditions, AMD-AA samples showed similar solution viscosity at 5 to 30% AA. When the AA-AMD polymer solutions were aged at elevated temperature, the AA content steadily increased because of hydrolysis reactions. When the AA content was 30 mol% or higher, the viscosity started to decrease, and the adsorption started to increase as the polymer solution was aged further. Thermal stability improved when ATBS was included in the polymer structure. In addition, sulfonated polyacrylamide samples showed constant initial viscosity yields and decreasing initial adsorption with increasing ATBS content. The samples showed that the maximum observed apparent in-situ viscosity increased when the bulk viscosity and relaxation time of the solution increased. The information generated in this study can be used to aid in the selection of the most optimal polyacrylamide chemistry, which may not necessarily be the standard 30% AA and 70% AMD copolymer, for sandstone fields operating with moderate/high salinity brines at the upper end of AA-AMD temperature tolerance.

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.

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.