Offshore Large Scale Polymer Flood Implementation at Chengdao Field

This paper presents the implementation of chemical enhanced oil recovery (CEOR) on the offshore platform CB22F, detailing its impact over three years and proposing improvements for future deployments. It discusses the project's effects, such as increased oil production, reduced water cut, and lowered CO2 emissions, while sharing insights for optimizing future CEOR designs on two newly sanctioned platforms. The CEOR strategy on CB22F has shown significant outcomes, demonstrated by an increase in oil production, a reduction in water cut, and a decrease in CO2 emissions. Oil production increased by 663 of barrels per day (b/d), the water cut decreased from 90% to 80.5%, reducing the volumes of water handled. This decrease in water cut lowered energy consumption for water pumping and chemical treatment costs for produced water, leading to a reduction in cost and CO2 emissions to produce one barrel of oil. The test area began showing positive effects by June 2021, with a significant decrease in water content in produced fluids in 2022 and a rapid increase in oil output. By the end of March 2024, the water cut stabilized around 80.5%, and the cumulative oil increase from the 44 effective production wells reached 3,800,000 barrels, corresponding to a 4.27% increase in oil recovery. This cumulative increase translates to 28.9 tons of oil per ton of polymer injected, indicating the project's economic viability. Building on the success of CB22F, CEOR will be implemented on two newly sanctioned platforms with designs incorporating improvements learned from CB22F's experience. Bulk polymer delivery via pneumatic transfer will mitigate hoisting risks, improve occupational health, increase offshore storage capacity, and reduce delivery rotations, thus decreasing CO2 emissions associated with logistic operations. An integrated injection system will involve a centralized polymer injection system on the main platform, facilitating efficient distribution to both main and satellite platforms. The introduction of new Conical Pressure Reducer (CPR) skids, equipped with low shear valves, will regulate injection pressure, and adapt the polymer concentration for individual wells, minimizing polymer degradation and footprint compared to conventional methods. To address higher polymer/surfactant concentrations in produced fluids, concerns regarding emulsification are being managed through the development of new, high-efficiency water clarifiers. These improvements, guided by CB22F's experience, are expected to further optimize CEOR performance and efficiency on future platforms. This paper provides insights for engineers by demonstrating a successful CEOR implementation with concrete results and data, sharing practical improvements for future CEOR designs on offshore platforms, addressing potential challenges, and proposing viable solutions. Additionally, it contributes to knowledge on CO2 reduction strategies in oil and gas production, highlighting the environmental benefits alongside the financial gains. The reduction in CO2 emissions per barrel of oil produced underscores the broader impact of the project beyond immediate financial gains, contributing to the long-term sustainability of oil production operations.

Multiobjective design and optimization of polymer flood performance

Casabe field reservoir characteristics are multilayer, geological complexity, vertical/areal heterogeneity and commingled production. Due large difference in mobility between oil and water (M ~ 20) and the maturity of water flooding, several operational problems have arisen, such as, increase of water cut, channeling, sand production, etc. These problems together with the high remaining reserves and identification of bypassed oil, were the main reasons to evaluate EOR process as a solution to increase the recovery factor. A reduced Cycle Time was created to reduce the time from design to full field implementation which involves the following phases: Screening/Conceptual Design, Pilot Design, Drilling-Workover and Facilities, Operation & Surveillance, Pilot Expansion, Full Field Development Plan, Reserves & FID. This strategy is based on multitask parallel process to allow fast track decision making and activities execution for a fast pilot implementation, which allowed to implement the EOR pilot in 24 months form the screening to pilot Operation & Surveillance. After the screening, polymer flooding was considered for mobility ratio modification to improve sweep efficiency and therefore increase RF. The best producer layers were selected, based on the areal continuity and residual oil in place, as target sands for polymer injection. One pattern was selected for the pilot. Laboratory tests, along with reservoir simulation confirmed the potential of chemical EOR in the selected sands and pilot area. Polymer injection was performed in four injector wells of the selected pattern. The polymer flooding process was monitored in the central producer and in the eight producers of the second line. A surveillance plan was implemented to collect the information required to evaluate, with the lowest uncertainty, the results of this pilot. An observation well was drilled to monitored changes in oil saturation. The surveillance plan was critical to be able to control the polymer injection process, to have a proper technical evaluation of the pilot and to optimize costs during the future expansion and full field implementation. Polymer flooding have increased the RF on the selected area. The fast-tracking strategy for an EOR project execution was successfully implemented in Casabe Field and the pilot was delivered in 2 years proving the concept of 5-year road map it is possible. The reduced Cycle Time (5-year Road Map) could be used as reference for implementation of new EOR pilots in other fields in shorter time and optimizing resources. The workflows used and the analysis procedures created for this pilot could be used as reference for the implementation of future pilots in fields with similar characteristics.

Polymer Flooding has been shown to increase oil production. The reason for increasing oil production is acceleration along flow paths but also flow diversion from higher permeability to lower permeability areas. Tracer tests performed in the 8 TH Reservoir in Austria prior, during and after polymer flooding show that the flow system dramatically changed. The connected volumes from injector to producer as well as the flow heterogeneity were influenced and substantial incremental oil produced. A number of tracer tests were performed in the pilot area of a polymer flood at various times. In addition, pressure data and polymer rheology was analyzed. The tracer results were used to calculate flow pattern, dynamic Lorentz coefficient and connected volumes. Pressure data were used in combination with geomechanical modelling to investigate the injection regime (matrix or fractures). The interpretation of the data was combined with the determination of incremental oil production based on simulation. The tracer tests reveal the dramatic changes in flow patterns, connected volume changes by more than a factor of three occurred and the Lorentz coefficient indicating the heterogeneity of flow changed by more than a factor of two. The injection regime changed from injection under matrix conditions prior to polymer flooding to injection under fracturing conditions during polymer injection and back to injection in matrix conditions during chase water injection. The reason for the changes in injection conditions is the near-wellbore viscoelastic rheology of the High Molecular Weight Polymers which were used. The growth of fractures leads to additional alteration of flow paths. The design of polymer flooding needs to take into account that flow paths are not only changed due to the reduction in water relative permeability resulting from polymer adsorbing to the rock and the increased viscosity of the injected fluid but also owing to changes in injection regime. The changes in injection regime might lead to early breakthrough of chase water as it might not flow along the same paths as the polymer solution.

Daqing Oil Field is the largest continental oil field in China. It is a large heterogeneous sandstone oil field with various permeability layers in longitudinal. Polymer flooding plays an important role in Daqing Oil Field which has recovered 10 million tons oil per year for 11 years. In the process of commingled polymer injection, most of the solution enters high permeability layers. Consequently, low permeability layers cannot be swept effectively which limits the recovery rate of polymer flooding. Based on the successful experiences of separate layer water flooding technology applied in Daqing Oil Field, several separate layer polymer flooding techniques were developed. The purpose of this technology is to inject polymer solution into pay zones separately with different pressure and flow rate according to reservoir properties, getting a stable injection profile of polymer solution in longitudinal direction so as to improve the overall recovery rate. The key points of this technology lie in three respects: First, the injected polymer solution should have a stable flow rate and pressure difference in the whole duration of polymer flooding. Second, the injected polymer solution should keep a higher viscosity to ensure EOR result of polymer flooding. Thirdly, the economic factor must be considered. This paper presents a unique separate polymer injection technology which solves the above issues effectively. The injected nozzle is designed into a special streamline style with different stages. When polymer solution flows through the nozzle, the molecular chains of polymer will expand and contract, creating an additional pressure difference. The more stages it has, the higher pressure difference can be reached. Furthermore, the shape of nozzle is optimized by simulation tools to ensure the minimum viscosity loss of polymer solution during the injection. After the optimal design, the maximum additional pressure difference of this nozzle can reach 2.5 MPa at the injection flowrate of 50 m3/d as well as viscosity loss ratio is less than 6%. This technology has been applied in 6464 wells in Daqing Oil Field. The producing degree of reserve was improved from 62.8 to 74.7% and oil recovery rate was improved by 2%. It is a remarkable core technology for sandstone oil fields in polymer flooding period. This technology has a brilliant future in the development of mature oil field.

A significant portion of the world's oil reserves are trapped in carbonate reservoirs, many of which are located in the Middle East. Polymer EOR in the carbonate reservoirs tends to be challenging due to limited injectivity and reservoir heterogeneity. This paper presents field results of a successful polymer EOR pilot in the Umm Gudair Minagish Oolite (UGMO) reservoir using treated effluent water at a salinity of up to 257,000 ppm and a reservoir temperature of 72°C. A suitable polymer was identified for UGMO polymer EOR based on extensive laboratory evaluation. Work was then geared towards the implementation of a pilot, mainly to de-risk polymer injectivity using an injector and an offsetting producer located nearly ~87m away. Before starting the pilot operations, a representative sector reservoir model was extracted, history-matched and calibrated using available data to design the envisaged pilot. Thereafter, pilot operations were carried out to generate reliable data using a fit-for-purpose surveillance program and surface facility. The acquired field data were then used to calibrate a high-resolution reservoir simulation model that was used for techno-economic optimization. Based on actual field data, it was observed that polymer injectivity far exceeded original simulation-based expectations. Field operations indicated limited polymer dissolution time, in the range of 1 to 2 hours, despite the extremely high-salinity effluent water that was used. Injected polymer concentration was progressively increased, reaching 2,500 ppm and a surface viscosity of 17 cP, at an injection rate of 3,500 BPD, while staying below the pre-defined maximum allowable injection pressure. Polymer breakthrough was detected at the nearest producer after approximately 3 months of polymer injection, thus indicating favourable sweep efficiency. Resistance factors were found to be more responsive to variations in injection rates as opposed to polymer concentrations as evident from downhole pressure data. Calculated in-situ viscosities were within the expected range and the injected polymer solution demonstrated non-Newtonian pseudo-plastic behavior in line with previously acquired lab data. Based on downhole pressure data, polymer injection was maintained under matrix conditions with no evidence of induced fractures. High-resolution reservoir simulation results indicate promising techno-economic results in terms of oil recovery and cost, thus indicated the feasibility of achieving a Unit-Technical-Cost (UTC) of approximately $20.5/incremental barrel of oil over a waterflood infill case. This paper sheds light on the feasibility of polymer-flooding for a deep carbonate reservoir, using extremely high-salinity effluent water, at a reservoir temperature of 72°C. Techno-economic evaluation of field results is promising. Work is in progress to pave the way for UGMO phased commercial polymer-flooding development on a fast-track basis.

Polymer flooding has become one of the most successful chemical EOR technologies, yet interpreting field performance remains challenging, particularly in reservoirs developed with horizontal wells. Conventional reservoir simulation can provide detailed insights, but it requires significant time, effort, and data conditioning. Simplified models, in contrast, offer an opportunity to rapidly extract key performance indicators such as swept pore volume, and heterogeneity directly from production and injection data. This work explores the application of simplified analytical approaches to the Milne Point polymer flood project in Alaska, one of the largest and longest-running field projects worldwide. More than six years of horizontal well polymer flood data will be evaluated using spreadsheet-based workflows designed to be transparent, rapid, and adaptable. Three Koval-type modeling techniques are possible, ranging from a simple model of volumetric sweep efficiency, the Mollaei model for tertiary floods, and the Jain model that accounts for interactions between banks. We present results from the first two here. The planned analysis is expected to provide estimates of contacted pore volume, and inferred heterogeneity in polymer floods, as well as insights into the in-situ mobility control achieved with polymer injection. A further outcome will be the development of a practical workflow for applying simplified models to horizontal well projects, complementing conventional simulation studies. To our knowledge, this represents the first systematic attempt to apply these simplified modeling methods to polymer flooding in horizontal wells. By combining established concepts with new applications, the work aims to deliver rapid interpretation tools and fresh perspectives on the performance of large-scale polymer EOR projects.

Polymer flood (PF) applications have increasingly been extended to medium-to-heavy oil reservoirs for enhanced displacement, sweep efficiency and improving the ultimate recovery. The relatively low carbon footprint and gas-light nature has made PF as an attractive way-forward EOR technique. This study, a follow-up of SPE-200207-MS, intends to develop theoretical based considerations, utilizing detailed high-resolution simulations, for optimizing an ongoing large-scale polymer flood application in Oman. The study intends to propose transformation of the ongoing polymer flood to a cost competitive polymer development strategy with minimal trade-off on recovery, while reducing the operational challenges. To these effects, this research uses the advanced simulation capabilities to investigate the subjects of 1) optimal polymer slug-size for multitude of geological scenarios and scales, 2) phenomenon of viscous fingering/instabilities and how does it scale from core- plug to field, and 3) concepts of polymer grading/tapering and related cost savings. The study builds on the foundation laid for holistic simulations study presented in preceding paper SPE- 200207-MS, capturing the details of polymer flow-physics. It starts with understanding the nature of polymer/polymer and polymer/water type displacements and stabilities. It encompasses modelling viscous fingering/instabilities in a range of model set-ups, starting from high resolution core-scale 2D models to 3D sector models incorporating varying degrees of geological heterogeneities. The understanding of unstable displacement gained with different high-resolution models is then extended to investigate the phenomena of polymer/water mixing, Water-Alternating-Polymer (WAP) recovery and polymer grading (tapering). Different prevailing concepts of polymer grading on the likes of those proposed by Claridge, Ligthelm-Schulte and Stegemeier in combination with various mixing rules are investigated and potential polymer savings for development strategies are evaluated. Research outcomes are integrated to formulate the optimal polymer slug size and viscosity requirements, demonstrated with creaming curve analyses for a variety of reservoir systems. Improved recovery performance and lower cost are achieved, underpinned by eliminating Water-Alternating-Polymer type of flooding. This was achieved with better design of polymer injection schemes encapsulating grading philosophies. This results not only in significant polymer savings (and hence, cost) but also reduces constraints/load-factor on injection facilities. The study highlights significant scope for optimizing polymer flood in fields both in terms of long-term improved recovery performance at reduced cost as well as tackling the short-term operational challenges, potentially influencing the business bottom-line. It reveals that adequate polymer grading design can potentially yield polymer saving of 26%-36% with minimal trade-off on recovery. Moreover, such initiatives and optimization of development strategy not only ensures smoother operations but also significantly improves the energy efficiency/utilization per barrel of oil produced and reduces the GHG intensity of such EOR projects.

The Suffield Caen reservoir contains 17°API heavy oil and the pool has been under waterflooding since 1996 with water cut of 96%. Primary and secondary oil recovery is 15 – 20% of OOIP. A major problem encountered in waterflood was poor sweep efficiency and high water cut caused by high water/oil mobility ratio, as water quickly broke through the reservoir owing to fingering effects. It is known that sweep efficiency during waterflood can be improved significantly by increasing the viscosity of injected water by use of polymer solution, thus generating a more favorable mobility ratio and enhancing oil recovery. The results of reservoir simulation studies suggested that polymer flood would achieve incremental recovery factor of 7 – 12%, and coreflood results indicated that 29 –32% of incremental recovery is achievable by 0.5 pore volume (PV) of polymer injection. Core floods including polymer, surfactant/polymer(S/P) and alkali/surfactant/polymer (A/S/P) were conducted through lab experiments and eventually polymer flood was selected as a pilot project to improve oil recovery for the Caen reservoir on the basis of polymer, S/P and A/S/P core flood results and project economic evaluation. Polymer injection started in the reservoir 15 months ago and a very positive response has been seen as oil cut has increased to 10% from 5% and oil production rose to 600 bbl/d from 400 bbl/d. Therefore, the polymer flood pilot project is continually implemented and the polymer flood is planned to extend to similar reservoirs in the Suffield area. There is a large amount of conventional heavy oil resaves in the West Canada Basin, so far the primary recovery factor is only 10%, there is a big potential to enhance oil recovery by polymer flood. This polymer flood pilot project provides valuable experiences and guidance to field application.

Effective oil displacement from a reservoir requires adequate and properly directed pressure gradients in areas of high oil saturation. If the polymer bank is too large or too viscous during a polymer flood, the pressure drop from the injection well to the polymer front may act as a pressure barrier by usurping most of the downstream driving force for oil displacement. Polymer injection pressures must be limited. The maximum allowable injection pressure is commonly constrained by caprock integrity, injection equipment, and/or regulations, even though fractures can be beneficial to polymer injectivity (and even sweep efficiency in some cases). This paper examines when the pressure-barrier concept limits the size and viscosity of the polymer bank during a polymer flood. Both analytical and numerical methods are used to address this issue. We examine the relevance of the pressure barrier concept for a wide variety of circumstances, including oil viscosities ranging from 10-cp (like at Daqing, China) to 1650-cp (like at Pelican Lake, Alberta), vertical wells (like at Tambaredjo, Suriname) versus horizontal wells (like at Milne Point, Alaska), single versus multiple layered reservoirs, permeability contrast, and with versus with crossflow between layers. We also examine the relation between the pressure-barrier concept and fractures and fracture extension during polymer injection. We demonstrate that in reservoirs with single layers, the pressure-barrier concept only limits the optimum viscosity of the injected polymer if the mobility of the polymer bank is less than the mobility of the displaced oil bank. The same is true for multi-zoned reservoirs with no crossflow between layers. Thus, for these cases, the optimum polymer viscosity is likely to be dictated by the mobility of the oil bank, unless other factors (like fracture extension) intervene. For multi-zoned reservoirs with free crossflow between layers, the situation is different. A compromise must be reached between injected polymer viscosity and the efficiency of oil recovery. The relevance of our findings is applied to operations for several existing polymer floods. This work is particularly relevant to viscous-oil reservoirs (like Pelican Lake and others) where the injected polymer viscosities are substantially lower than the oil viscosity

Recent studies have shown that enhanced oil recovery will be the focal point for approximately 50% of the global oil production in the upcoming two-three decades. According to the several ballpark studies conducted on EOR techniques, results show that for reservoirs with oil viscosities ranging from 10 to 150 m Pa.s., polymer flooding seems to be an ideal development strategy. However, when the oil viscosities exceed 150 m Pa.s., polymer injectivity and pumping efficiencies can turn out to be major inhibiting factors, thereby limiting the range of oil viscosities for which polymer flooding can be utilized. The core reason for this is that the values of viscosity for the injected water containing polymer, calculated for the beneficial mobility ratio, can lead to the inhibiting factor stated above. Previously conducted lab studies have shown that supramolecular systems are very resistant in high temperature - high salinity systems. To be able to achieve the easier injection, the injected supramolecular viscosity will be kept at lower values and then increased to the levels right before or upon contacting the oil in the reservoir. The core difference between conventional polymer systems and supramolecular polymer systems is that the latter disassemble and re-assemble as opposed to degradation when exposed to extreme shear stress and temperatures. It can therefore be said that supramolecular polymer systems are self-healing in nature. The phenomenon has been observed in cases where polymers with high molecular weight are forced through narrow flow channels. Though molecular division takes place, supramolecular systems have shown a tendency of reassembly later on. Therefore, adaptability of these systems to bounded or restricted environments can be established. This study will add the modeling and simulation components of supramolecular systems which can be effectively utilized in high temperature-high salinity conditions through adjustments to viscosities and interfacial properties of these assemblies. This will help compare the displacement efficiency of supramolecular systems which efficiently perform in a wide range of reservoirs such as thin zones, and reservoirs within permafrost conditions. This can significantly benefit the oil and gas companies worldwide in preparing a technically feasible, but also, a cost effective EOR development strategy, whenever polymer injection is of consideration.

For reservoirs exhibiting severe heterogeneity due to prolonged water flooding, conventional polymer flooding demonstrates limited capacity to alter reservoir properties under such conditions. Crosslinked polymer flooding, characterized by its three-dimensional network structure, significantly enhances reservoir conformance, sweep efficiency, and oil displacement efficiency, making it a key technique for strongly heterogeneous reservoirs in the middle to late stages of development. In this study, a geological model based on a one-injection–one-production well pattern was constructed to simulate the crosslinked polymer flooding process. The model incorporates critical factors including formation heterogeneity, wall adsorption, and the inaccessible pore volume associated with polymer injection. Using the Computer Modelling Group’s Steam, Thermal, and Advanced Processes Reservoir Simulator (CMG-STARS), model was validated through grid independence analysis and calibrated via history matching. A systematic investigation was conducted to assess the influence of key parameters—namely, crosslinked polymer concentration, injection rate, and injection strategy—on oil displacement performance. The results indicate that, under the studied conditions, a well spacing of 200 m, a mass concentration of 0.55%, and an injection rate of 400 m³/d effectively reduce polymer adsorption and shear degradation while promoting the formation of a stable gel, thereby enhancing plugging efficiency. An injection strategy initiated at a 35% water cut, combined with 2–3 alternating cycles, was found to mitigate water channeling through early-stage reservoir modification. This study identifies the dominant factors controlling the oil displacement performance of crosslinked polymer systems, clarifies their relative advantages and limitations compared to conventional polymers, and offers a reliable reference framework for parameter selection in field-scale crosslinked polymer flooding operations.

The recovery efficiency by polymer flooding is 10% higher than that of water flooding for main reservoirs in Daqing Oil Field, and yearly oil production rate by polymer injection has continuously reached over 10 million tons for 8 years. However, to further enhance oil recovery, it is very important to know how many oil remained in the reservoirs after polymer injection as well as its distribution. The paper took use of logging data of 200 new drilling wells to make macro analysis on remaining oil distribution after polymer injection, and based on the data of coring wells, collected from the same well group in Western Fault of B1 Region, before and after polymer flooding, respectively, core membrane fluorescence technology was used to conduct the analysis on microscopic remaining oil distribution. The macro analysis results indicate that swept thickness of the reservoir increased 21.4% from 68.6% of water flooding to 90% of polymer flooding, and oil saturation reduced 11.9% from 52.8% to 40.9%, and displacement efficiency has went up 7.6 percentages. The residual oil distribution after polymer flooding is scattered in horizontal direction, while it is interleaved in vertical direction. Following polymer flooding, 10.6% unswept thickness is mainly distributed in thick oil layers, and most of remaining oil within thick oil layers lies in the interlayers and at the top of thick oil layers, which its effective thickness is close to 80%. From the macro point, remaining oil is mainly located in distributary line or some places where injection and production relation is imperfect or the phase is changed, and oil saturation located in distributary line is 4.4 percentages higher than that along mainstream line. The micro analysis results show that the behavior of remain oil distribution is similar to water flooding, which is mainly controlled by capillary force.

ABSTRACTIn recent years, polymer flood of heavy oil has been extensively studied in laboratories and successfully applied in several fields. Polymer flooding is the most successful chemical enhanced oil recovery method. However, still, the need for a large amount of polymer, leading to high operational costs, presents a big challenge in technologies. This challenge can be addressed by considering the newly emerging nanomaterials. In this work, the author focuses on roles of TiO2 nanoparticles on polymer viscosity and improve recovery in heavy oil recovery. He present the results obtained from a coreflood experiment with polymer injection in heavy oil at 1320 mPa.sec viscosity. Nanopolymer exhibits an outstanding flow behavior and enhanced oil recovery performance in coreflood displacement tests compared to base polymers. The results indicate that polymer flooding with higher viscosity can significantly improve oil recovery. Flooding test showed about 4% increase in oil recovery for nanopolymer solution in comparison with polymer solution after one pore volume fluid injection.

SummaryPolymer flooding can significantly improve sweep and delay breakthrough of injected water, thereby increasing oil recovery. Polymer viscosity degrades in reservoirs with high-salinity brines, so it is advantageous to inject low-salinity water as a preflush. Low-salinity waterflooding (LSW) can also improve local-displacement efficiency by changing the wettability of the reservoir rock from oil-wet to more water-wet. The mechanism for wettability alteration for LSW in sandstones is not very well-understood; however, experiments and field studies strongly support that cation-exchange (CE) reactions are the key elements in wettability alteration. The complex coupled effects of CE reactions, polymer properties, and multiphase flow and transport have not been explained to date.This paper presents the first analytical solutions for the coupled synergistic behavior of LSW and polymer flooding considering CE reactions, wettability alteration, adsorption, inaccessible pore volume (IPV), and salinity effects on polymer viscosity. A mechanistic approach that includes the CE of Ca2+, Mg2+, and Na+ is used to model the wettability alteration. The aqueous phase viscosity is a function of polymer and salt concentrations. Then, the coupled multiphase-flow and reactive-transport model is decoupled into three simpler subproblems—the first in which CE reactions are solved, the second in which a variable polymer concentration can be added to the reaction path, and the third in which fractional flows can be mapped onto the fixed cation and polymer-concentration paths. The solutions are used to develop a front-tracking algorithm, which can solve the slug-injection problem of low-salinity water as a preflush followed by polymer. The results are verified with experimental data and PennSim (2013), a general-purpose compositional simulator.The analytical solutions show that decoupling allows for estimation of key modeling parameters from experimental data, without considering the chemical reactions. Recovery can be significantly enhanced by a low-salinity preflush before polymer injection. For the cases studied, the improved oil recovery (IOR) for a chemically tuned low-salinity polymer (LSP) flood can be as much as 10% original oil in place (OOIP) greater than with considering polymer alone. The results show the structure of the solutions, and, in particular, the velocity of multiple shocks that develop. These shocks can interact, changing recovery. For example, poor recoveries obtained in corefloods for small-slug sizes of low salinity are explained by the intersection of shocks without considering mixing. The solutions can also be used to benchmark numerical solutions and for experimental design. We demonstrate the potential of LSP flooding as a less-expensive and more-effective way for performing polymer flooding when the reservoir wettability can be altered with chemically tuned low-salinity brine.