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Collaborating Authors
Results
Polymer Stabilized Foam Rheology and Stability for Unconventional EOR Application
Griffith, Christopher (Chevron) | Jin, Julia (Chevron) | Linnemeyer, Harry (Chevron) | Pinnawala, Gayani (Chevron) | Aminzadeh, Behdad (Chevron) | Lau, Samuel (Chevron) | Kim, Do Hoon (Chevron) | Alexis, Dennis (Chevron) | Malik, Taimur (Chevron) | Dwarakanath, Varadarajan (Chevron)
Abstract It has been shownthat injecting surfactants into unconventional hydraulically fractured wells can improve oil recovery. It is hypothesized that oil recovery can be further improved by more efficiently distributing surfactants into the reservoir using foam. The challenge is that in high temperature applications (e.g., 240 F) many of these formulations may not make stable foams as they have only moderate foaming properties (short half-life). Therefore, we are evaluating polymers that can be used to improve foam stability in high temperature wells which has the potential to improve oil recovery beyond surfactant only injection.Surfactant stabilized nitrogen foams were evaluated using a foam rheometer at pressures and temperatures representative of a field pilot well. The evaluation process consisted of measuring baseline properties (foam viscosity and stability) of a surfactant stabilized foam without any added stabilizer. Next, conventional enhanced oil recovery polymers (HPAMs, modified-HPAMs, and nonionic polymers) were added at different concentrations to determine their impacts on foam stability. Our results demonstrate that inclusion of a relatively low concentration (0.05 wt% – 0.2 wt%) of polymer has a pronounced impact on foam stability. It was determined that reservoir temperature plays a key role in selecting astabilizing polymer. For example, at higher temperatures (>240 F), sulfonated HPAM polymers at just 0.2 wt% more than doubled the stability of the foam. The polymer that was selected from this lab work was tested in a foam field trial in an unconventional well. It is thought that improved foam stability could potentially help improve the distribution of surfactants in fracture network and further improve oil recovery.
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > South Dakota > Williston Basin > Bakken Shale Formation (0.99)
- North America > United States > North Dakota > Williston Basin > Bakken Shale Formation (0.99)
- North America > United States > Montana > Williston Basin > Bakken Shale Formation (0.99)
Novel Application of Polyethylene Oxide Polymer for EOR from Oil-Wet Carbonates
Trine, Eric Brandon (Ultimate EOR Services, LLC) | Pope, Gary Arnold (Ultimate EOR Services, LLC) | Britton, Chris James (Ultimate EOR Services, LLC) | Dean, Robert Matthew (Ultimate EOR Services, LLC) | Driver, Jonathan William (Ultimate EOR Services, LLC)
Abstract The objective of this study was to test the performance of high-molecular weight polyethylene oxide (PEO) polymer in a low-permeability, oil-wet carbonate reservoir rock. Conventional HPAM polymers of similar molecular weight did not exhibit acceptable transport in the same rock, so PEO was explored as an alternative polymer. Viscosity, pressure drop across each section of the core, oil recovery, and polymer retention were measured. The PEO polymer showed good transport in the 23 mD reservoir carbonate core and reduced the residual saturation from 0.29 to 0.17. The reduction of residual oil saturation after polymer flooding using PEO was unexpected and potentially significant.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.88)
Fast Screening of LSW Brines Using QCM-D and Crude Oil-Brine Interface Analogs
Yutkin, M. P. (King Abdullah University of Science and Technology) | Kaprielova, K. M. (King Abdullah University of Science and Technology) | Kamireddy, S. (King Abdullah University of Science and Technology) | Gmira, A. (Saudi Aramco) | Ayirala, S. C. (Saudi Aramco) | Radke, C. J. (University of California – Berkeley) | Patzek, T. W. (KAUST)
Abstract This work focuses on a potentially economic incremental oil-recovery process, where a brine amended with inexpensive salts (in contrast to expensive surfactants and other chemicals) is injected into a reservoir to increase oil production. Historically, this process received the name of low salinity waterflooding (LSW) although the salinity is not always low(er). Nevertheless, we keep using this terminology for historical reasons. The idea of LSW has been known for three decades, but to the best of our knowledge no specific brine recipes that guarantee success have been presented so far. The reasons hide in the problem's complexity, disagreements in the scientific community, and a race to publish rather than to understand the fundamental principles behind the process. In this paper, we present an experimental model system that captures many of the important fundamental features of the natural process of crude oil attachment to mineral surfaces, but at the same time decomposes this complex process into simpler parts that can be more precisely controlled and understood. We systematically investigate the first-order chemical interactions contributing to the well-known strong attachment of crude oil to minerals using SiO2 as a mineral for its surface chemistry simplicity. Our preliminary results suggest that magnesium and sulfate ions are potent in detaching amino/ammonium-based linkages of crude oil with a SiO2 surface. However, when used together in the form of MgSO4, they lose part of their activity to the formation of a MgSO4 ion pairs. We also find that sulfate-detachment propensity stems not from the interaction with prototype mineral surface, but rather from the interactions with the crude oil-brine interface analog. We continue the systematic study of the ion effects on crude oil detachment, with and more results following in the future.
- Research Report > New Finding (0.66)
- Research Report > Experimental Study (0.48)
Polymer Injectivity Enhancement Using Chemical Stimulation: A Multi-Dimensional Study
Chandrasekhar, Sriram (Chevron Technical Center, a division of Chevron USA Inc.) | Alexis, Dennis Arun (Chevron Technical Center, a division of Chevron USA Inc.) | Jin, Julia (Chevron Technical Center, a division of Chevron USA Inc.) | Malik, Taimur (Chevron Technical Center, a division of Chevron USA Inc.) | Dwarakanath, Varadarajan (Chevron Technical Center, a division of Chevron USA Inc.)
Abstract Chevron injected emulsion polymer in the Captain field, offshore UK in the last decade at various scales (Poulsen et al., 2018). Pilot horizontal wells had exhibited faster than designed injectivity decline and Jackson et al. (2019) documented the causes to include oleic phase damage from a) injection of produced water containing crude oil after imperfect separation, and b) entrainment of injected emulsion polymer’s carrier oil. The wells were remediated with a surfactant stimulation package (Alexis et al., 2021; Dwarakanath et al., 2016). The remediation boosted the water relative permeability near wellbore which enhanced injectivity and allowed higher processing rates for subsequent continuous polymer injection. In this work, we conducted a set of core floods in slabs of surrogate rock of varying dimension and patterns to demonstrate the beneficial effect of near wellbore stimulation in the general case. 0.04 PV of the remediation package was injected and we show consistent injectivity enhancement across the experiments. We demonstrate the dominant effect of well skin treatment on the pressure drop profile compared to flow resistance from a) residual oil saturation and b) viscous fingering. The result is an important reminder for injectivity maintenance for high polymer flood processing rates for the life of the project. Clean injection fluids were demonstrated to maintain injectivity. We show applicability of stimulation for injectors into viscous oil reservoirs with adverse viscosity ratio. The robust nature of the remediation package developed by Alexis et al. (2021) is also shown, working to efficacy on viscous oil, as well as in situ phase separated polymer. We estimated skin and stimulation depth for a line drive case with low chemical dosage finding that 0.04 pore volumes of surfactant injection at 0.33 oil saturation units gave injectivity improvement of 31%. Surfactant stimulation is thus broadly applicable to wells with oleic phase skin.
Abstract Polyacrylamide-based friction reducer is commonly used in well completion for unconventional reservoirs. However, residual polymer trapped in the near well-bore region could create unintended flow restrictions and could negatively impact oil production. An eco-friendly approach to regain conductivity was developed by stimulating indigenous bacteria for residual polymer biodegradation. In this work, a series of laboratory experiments were conducted using produced water and oil from Permian Basin, polyacrylamide-based polymer, and a modified nutrient recipe that contained 100 to 300 ppm of inorganic salts. The sealed sample vials containing water, oil, and polymer were prepared in a sterilized anaerobic chamber and then kept in a 160° F incubator to simulate the reservoir condition. Feasibility tests of bacteria growth and biodegradation evaluation of polymer were conducted using an optical laser microscopic system with bacteria tagged with fluorescent dye. Size regression was calculated and applied to a mathematical model based on actual fracture aperture distribution data from shale formation. The indigenous bacteria were successfully stimulated with and without the existence of the friction reducer. It was observed that the size of polymer particles decreased from over 300 µm to less than 20 µm after 15 days. Under the condition of produced water injection, 140° F reservoir temperature, and anaerobic environment, about 30% of the natural fractures in shale were calculated to be damaged and remediated within 15 days. This work is a pioneer research on microbial EOR application in unconventional reservoirs with only indigenous bacteria involved. In field applications, only an extremely low amount of nutrient is required in this process which provides great economic potential. Additionally, the nutrients introduced into the reservoirs will be fully consumed by bacteria during treatment, and the bacteria will be decomposed into organic molecules soon after the treatment. Thus, this technique is environmental- and economical- friendly for the purpose of polymer damage remediation to maximize the recoverable.
- North America > United States > Texas (0.25)
- North America > United States > New Mexico (0.25)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (21 more...)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (0.96)
- Health, Safety, Environment & Sustainability > Environment > Remediation and land reclamation (0.89)
- Health, Safety, Environment & Sustainability > Environment > Water use, produced water discharge and disposal (0.75)
- (2 more...)
Screening of Topside Challenges Related to Polymer Presence in the Back Produced Fluids – Casabe Case Study
Mouret, Aurélie (IFP Energies Nouvelles) | Blazquez-Egea, Christian (IFP Energies Nouvelles) | Hénaut, Isabelle (IFP Energies Nouvelles) | Jermann, Cyril (IFP Energies Nouvelles) | Salaün, Mathieu (Solvay) | Quintero, Henderson (Ecopetrol) | Gutierrez, Mauricio (Ecopetrol) | Acosta, Tito (Ecopetrol) | Jimenez, Robinson (Ecopetrol) | Vargas, Nadine (Ecopetrol)
Abstract Polymer enhanced oil recovery (EOR) pilots were implemented in various mature oilfield reservoirs in Colombia with encouraging results. That chemical EOR technology is often considered as a promising process to faster recover oil. To increase the chance of success of such an industrial project it is important not to neglect the potential impact of residual polymer in back produced effluents. The objective of this work is to highlight the impact of back-produced EOR polymer at the laboratory scale on various topside equipment before deploying the polymer injection at wider scale in a heavy oil field (18° API). A topside facility review was first performed to collect operational conditions and parameters, to identify applied treatment technologies and to define relevant sampling locations for the laboratory study. The impact of the residual acrylamide/ATBS ter-polymer selected for the future polymer implementation was then explored in a set of experiments as part of a dedicated laboratory workflow representing the whole surface treatment chain. The scope of the study has covered primary separation, static gravity water clarifying, deep-bed filtration and heater fouling. Large residual polymer concentration and water cut ranges were investigated to anticipate some produced fluid composition change over time. In the case studied, the selected polymer does not stabilize tight water-in-oil emulsions, but it has a negative impact on the water quality. Some compatibility issues are observed with incumbent demulsifiers, which seems to be sensitive to both polymer concentration and water cut. The fouling risk of heat exchanger is very low in the testing conditions. In the water de-oiling side, filtration and gravity settling performance are reduced but the right chemical and equipment combination enables to obtain a better water quality and to meet injection specifications targets. Novel/Additive Information: This work illustrates that management of produced fluid containing EOR polymer has to be considered as early as possible in the project implementation. It also points out that laboratory experiments are useful to better appraise and mitigate the potential operational issues. All the results obtained in such a study are valuable guideline and input data for treatment facilities upgrade studies. In polymer flooding roadmap implementation, it is key to bond operational conditions and laboratory parameters in order to be as close as possible to the field conditions as each case is unique.
- South America > Colombia (0.67)
- North America > United States (0.46)
- Asia > India (0.46)
- Research Report > New Finding (0.68)
- Research Report > Experimental Study (0.48)
- Water & Waste Management > Water Management > Lifecycle > Treatment (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- South America > Colombia > Santander Department > Middle Magdalena Basin > Yariguí-Cantagallo Field (0.99)
- South America > Colombia > Bolivar Department > Middle Magdalena Basin > Yariguí-Cantagallo Field (0.99)
- South America > Colombia > Antioquia Department > Middle Magdalena Basin > Casabe Field (0.99)
- (8 more...)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Downhole chemical treatments and fluid compatibility (1.00)
- Health, Safety, Environment & Sustainability > Environment > Water use, produced water discharge and disposal (1.00)
Polymer Containing Produced Fluid Treatment for Re-Injection: Lab Development to Field Deployment
Pinnawala, Gayani Wasana (Chevron Technical Center, a Division of Chevron U.S.A. Inc) | Subrahmanyan, Sumitra (Chevron Technical Center, a Division of Chevron U.S.A. Inc) | Alexis, Dennis Arun (Chevron Technical Center, a Division of Chevron U.S.A. Inc) | Palayangoda, Sujeewa Senarath (Chevron Technical Center, a Division of Chevron U.S.A. Inc) | Linnemeyer, Harold (Chevron Technical Center, a Division of Chevron U.S.A. Inc) | Matovic, Gojko (Chevron Technical Center, a Division of Chevron U.S.A. Inc) | Kim, Do Hoon (Chevron Oronite a Division of Chevron U.S.A. Inc.) | Theriot, Timothy (Chevron Oronite a Division of Chevron U.S.A. Inc.) | Malik, Taimur (Chevron Technical Center, a Division of Chevron U.S.A. Inc) | Dwarakanath, Varadarajan (Chevron Technical Center, a Division of Chevron U.S.A. Inc)
Abstract Chemical Enhanced Oil Recovery operations involve injecting polymer and surfactants for enhanced recovery. Some of the polymer and surfactant are produced in the form of emulsions. The emulsions need to be treated to recover the oil and reuse water for mixing new polymer for injection. New treatment methods are required to effectively break these emulsions. While chemical treatment and other methods are effective in breaking emulsions formed by electric submersible pumps (ESP's), these methods are not successful in breaking emulsions formed by injected chemicals for CEOR. Reuse of produced water is important in off-shore as well as some on-shore fields. Produced water re-injection requires mixing of fresh polymer with fluid containing produced polymer and traces of oil, which can cause potential incompatibility. Ideally, removal of all produced polymer using a viscosity reducer followed by injection of fresh polymer will improve facility reliability and uptime. Sodium hypochlorite (NaOCl or bleach) was evaluated as a viscosity reducer (VR). Bleach can reduce the viscosity of any HPAM by breaking down the polymer. Polymer destruction fortuitously causes a breakdown of emulsions which releases oil from water and results in improved water quality. After destruction of HPAM, excess bleach was neutralized by chemical means using a neutralizer. After neutralization, the resulting water is free of excess bleach and can be reused for mixing fresh polymer for injection without the risk of degradation of newly mixed polymer. Activating the VR (acidic VR) by pH adjustment can enhance the performance of VR dramatically. Improved oil separation as well as polymer removal can be realized using this technique.
- North America > United States (0.68)
- Asia > Middle East > UAE (0.28)
- Asia > Middle East > Oman (0.28)
- Asia > China > Heilongjiang Province (0.28)
- Materials (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Treatment (0.94)
- Europe > United Kingdom > North Sea > Central North Sea > Moray Firth > Moray Firth Basin > Block 13/22a > Captain Field > Captain Formation (0.99)
- Europe > France > Chateaurenard Field (0.99)
- Asia > Middle East > Oman > Dhofar Governorate > South Oman Salt Basin > Marmul Field > Al-Qalata Formation (0.99)
- (2 more...)
Abstract The objective of this paper is to present a critical review of best practices for conducting laboratory experiments to evaluate chemical EOR. Some legacy methods and procedures are outdated and need to be updated to address their inherent flaws. This paper presents the reasons improvements are necessary and serves to introduce or highlight better methods, while providing a good resource to review past studies. Common laboratory methods and procedures used to evaluate chemical EOR are critically reviewed and discussed for polymer flooding, surfactant-polymer flooding, alkaline-surfactant-polymer flooding, alkaline-co-solvent-polymer flooding specifically but also apply to similar processes. The laboratory methods for evaluating chemical EOR include surfactant phase behavior, coreflooding, chemical adsorption and retention measurements, polymer residual resistance factor measurements, polymer transport, polymer filtration ratio measurements, polymer stability. The best methods and procedures for these and other measurements should take into account how the laboratory measurements will be used for making field-scale performance predictions, the type of oil reservoir, the chemical EOR process and many other factors. Conducting corefloods with a low residence time is an example of a common mistake. New or improved methods are introduced or highlighted to bring best practices to the forefront. New methods that are highlighted include Residence Time Distribution Analysis to determine polymer retention and IPV, polymer transport in cores with two-phases present, and the addition of solvents/pre-shearing for improved polymer transport. The state-of-the-art laboratory methods and procedures discussed herein yield more accurate, more scalable data that are needed for reservoir simulation predictions and field-scale applications of chemical EOR. The recommended best practices will provide a better understanding needed to help select the appropriate chemicals and to determine the optimal chemical mass for field applications of chemical EOR.
- North America > United States > Texas (0.93)
- Asia > Middle East (0.67)
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.67)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- South America > Suriname > North Atlantic Ocean > Guyana-Suriname Basin > Tambaredjo Field (0.99)
- South America > Guyana > North Atlantic Ocean > Guyana-Suriname Basin > Tambaredjo Field (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Fatehgarh Formation (0.99)
- (3 more...)
Re-Injection of Produced Polymer in EOR Projects to Improve Economics and Reduce Carbon Footprint
Ghosh, Pinaki (SNF Holding Company) | Wilton, Ryan R (SNF Holding Company) | Bowers, Annalise (SNF Holding Company) | O’Brien, Thomas (SNF Holding Company) | Cao, Yu (SNF Holding Company) | Wilson, Clayton (SNF Holding Company) | Metidji, Mahmoud Ould (SNF SA) | Dupuis, Guillaume (SNF SA) | Ravikiran, Ravi (SNF Holding Company)
Abstract Chemical Enhanced Oil Recovery (cEOR) flooding is one of the more attractive methods to improve oil recovery. However, during times of instability in the oil market, cost of specialized chemicals and necessary facilities for alkali-surfactant-polymer (ASP) or surfactant-polymer (SP) make this technology very expensive and challenging to implement in the field. In majority of cases, polymer flooding alone has proven to be the most cost-effective solution that has resulted in attractive and predictable return on investment. In recent times, challenging economic environment has operators looking for added economic and sustainable savings. The possibility of re-injection of produced polymer to offset injection concentration requirements can lead to reduced cost and longer sustainability of oil recovery; thus, offering a subsequent reduction in produced water treatment and a reduced full-cycle carbon footprint. This innovative approach is subject to conditions experienced in the surface facilities, as well as in the reservoir. As part of this study, different polymer chemistries were investigated for their mobility control in porous media and comparative effect on oil recovery trends in presence of produced fluid containing residual polymer. The initial fluid-fluid testing and lab characterization results were validated against a mature field EOR project for reduction in polymer requirement to achieve target viscosity. Monophasic flow behavior experiments were performed in Bentheimer and Berea outcrop cores, while oil recovery experiments were performed in Bentheimer outcrops with different polymer solutions – freshly made and combinations with residual produced polymer. In addition, comparative injectivity experiments with field and lab prepared solutions were performed in Bentheimer outcrop cores. Based on field observations and lab measurements, a 10-15% reduction in fresh polymer loading could be achieved through the re-utilization of water containing residual polymer in these specific field conditions. Similar screen factor measurements were obtained with increasing concentration of residual polymer solution. This agreed with the monophasic injectivity experiments in both outcrop cores that resulted in similar resistance factors for fresh polymer and blends with produced water containing residual polymer solution. Oil recovery experiments also resulted in similar oil displacement behavior (approximately 30-40% OOIP after 0.5 PV waterflood) for fresh and blends with sheared polymer solutions, validating no loss in recovery potential, with the added benefit of 10-15% polymer loading reduction.
- North America > United States (1.00)
- Asia (1.00)
- North America > Canada (0.93)
- Europe (0.68)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.47)
- Geology > Rock Type (0.46)
- Water & Waste Management > Water Management > Lifecycle > Treatment (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Louisiana > Pelican Lake Field (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Lloydminster Field (0.99)
- Europe > Austria > Vienna Basin > Matzen Field (0.99)
- Europe > Netherlands > North Sea > Dutch Sector > P09C License > Horizon Field > Vlieland Sandstone Formation (0.98)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Health, Safety, Environment & Sustainability > Sustainability/Social Responsibility > Sustainable development (1.00)
- Health, Safety, Environment & Sustainability > Environment > Water use, produced water discharge and disposal (1.00)
- Health, Safety, Environment & Sustainability > Environment > Climate change (1.00)
Confirmation of Polymer Viscosity Retention at the Captain Field Through Wellhead Sampling
Johnson, Geoffrey (Ithaca Energy) | Hesampour, Mehrdad (Kemira Oyj) | Toivonen, Susanna (Kemira Oyj) | Hanski, Sirkku (Kemira Oyj) | Sihvonen, Stina (Kemira Oyj) | Lugo, Nancy (Ithaca Energy) | McCallum, Jennifer (Ithaca Energy) | Pope, Michael (Ithaca Energy)
Abstract The Ithaca-operated Captain field is located in Block 13/22a in the U.K. sector of the North Sea, 130 km northeast of Aberdeen, in a water depth of 360 ft. The Captain Field has an adverse mobility ratio across all the producing reservoirs and so has undergone improved oil recovery by polymer flooding since 2011 using Anionic polyacrylamide (HPAM) in liquid form. This paper presents recent offshore wellhead sampling from the Captain facility that confirms high polymer solution viscosity retention from a producing well, even after significant mechanical degradation through the Electrical Submersible Pumps (ESP), which is used for artificial lift. The continuing commercial success of the Captain Field polymer flood is underpinned by maintaining polymer viscosity throughout the system. High polymer returns, combined with declining oil rates, may result in the continued operation of these wells to be unattractive. This paper summarises the data used to shut-in mature wells that are producing polymer to the surface, to enable the polymer flood to continue displacing oil to offset production wells. Samples were collected from the wellhead in oxygen free conditions into pressurized cylinders. The measurements in laboratory were taken inside a glove box to avoid oxygen ingress. The absence of oxygen was confirmed through measurements of dissolved oxygen and redox potential. Viscosity of the solutions have been measured with Brookfield viscometer inside the glove box and the results were compared to the expected viscosity from fresh non-degraded polymer solution. The expected viscosity was determined using a concentration – viscosity curve of a fresh polymer in synthetic Captain brine. Polymer solution concentration is measured on-site using KemConnect™ EOR, a time resolved fluorescence method, the collected samples were subsequently confirmed with size exclusion chromatography (SEC) in the laboratory. The polymer concentrations measured from these wellhead samples with KemConnect™ EOR were in the region of 700-900 ppm. Previously collected downhole viscosity samples confirmed >70% viscosity retention prior to being produced through the ESP, while 50-80% of the original viscosity was found to be retained after production through the ESP to the surface facilities under anaerobic conditions for the range of concentrations sampled. These findings demonstrate the resilience of the polymer product to degradation in a real-world operational setting. It also provides data that may be used to estimate the expected downhole polymer solution viscosity from wellhead samples for defined operating conditions. The ability to estimate polymer solution downhole viscosity retention from wellhead samples provides a simpler and less expensive method of estimating viscosity retention than downhole sampling, which is especially useful for wells that do not have downhole access for sample collection.