Polymers for application in high temperature and high salinity reservoirs – critical review of properties and aspects to consider for laboratory screening

A significant amount of oil resides in deep reservoirs characterized by relatively high temperature and high salinity. In such reservoirs, most available chemicals fluids for EOR have limited applicability. Even though recent effort has been dedicated to the development of high temperature polymers, there is no clear understanding of what would work best in those harsh environments. In addition, the oil and gas community is also evaluating potential applications of chemical EOR to offshore assets where similar conditions are often found. Field applications in harsh reservoirs have shown limited success in the use of polymers for improved oil recovery. Detail analysis reveals that screening of the fluids was done under ‘model’ laboratory conditions, using non-reservoir core samples and non-representative fluids. These facts have motivated research and development work towards understanding the type of polymers that may be suitable for use in high temperature and high salinity reservoirs and to determine the type of tests to use to assess their performance in a field application for use as lab screening criteria. In this paper, we provide a critical review of the available polymers for application in high temperature and high salinity reservoirs and summarize best practices for their laboratory screening though a recommended workflow.


Introduction
The increasing global energy demand relies heavily on the use of hydrocarbons; however, the discovery of oil and gas deposits is becoming increasingly difficult with findings in complex and challenging environments.
Most of the easily accessed oil is already depleted, and approximately 50% of the initial hydrocarbons remain trapped in the reservoirs. These facts are promoting the evaluation of enhanced oil recovery (EOR) methods as a way to sustain operations and satisfy the energy demand.
EOR technologies refer to a variety of methods aiming to recover stranded oil on partially depleted reservoirs. Some of the methods involve the injection of agents, a fluid or a combination of fluids into the reservoir (e.g.: chemical, gas, thermal and microbial). The injected fluid enhances the oil displacement resulting in lowering of the residual oil saturation. The injected fluids interact with the in-situ rock-fluid system (brine, oil, gas) and may generate conditions favorable for oil recovery, like lowering of the interfacial tension (IFT), inducing wettability alteration, developing preferential phase behavior, etc.
Chemical EOR methods have a long history of field implementation dating back to 1970's. The most popular of these methods is polymer flooding in use in several countries for over 40 years with various degree of success (Needham & Doe, 1987). Most polymer flooding field applications to date were done in reservoirs with in situ-temperature in the range 8°C-110°C, formation permeabilities values between 1 mD and 15 D, brine salinities ranging from 0,1 to 30 % TDS, and oil viscosities in the range of 0,01 cP to 2.000 cP. Polymer flooding is frequently done after waterflooding, attempting to address two types of problems: 1) low volumetric sweep and displacement efficiency, and 2) high residual oil.
The implementation of chemical EOR technologies is always a challenge since they involve multiple processes frequently addressed by several disciplines. In the last three decades, the most significant advances in the development of chemicals for EOR applications are found in the manufacturing of surfactants, polymers, co-solvents and gels. In fact, more new polymers were created in the last 10 years than in the previous 30 years for other oil production applications. Such a development has enabled the industry to consider the use of such chemicals for EOR with incremental recovery in the range of 20-30%; however, the range of application is quite limited based on the reservoir characteristics, in-situ temperature and brine salinity, and for the high cost involved.
Polymer flooding is one of the most attractive chemical enhanced oil recovery techniques. Its successful application has been related to the existence of favorable reservoir conditions. Most applications have been done in clastics reservoirs, although a few projects were implemented in carbonates. The main reason on the limited application in carbonates is due to challenges preserving the polymer properties at the in-situ high temperatures, and high salinity. Benefits of polymer flooding reported in the literature (Abidin, Puspasari & Nugroho, 2012) refer to the use of Xanthan Gum, PAM (polyacrylamide), HPAM (partially hydrolysed polyacrylamide), and sodium acrylate as co-polymer, for applications where the in-situ reservoir temperature was below 70°C. In general, these polymers enhance the rheological properties of the displacing fluid since the water-soluble polymers can improve the water-oil mobility ratio (Pinto, Herrera & Angarita, 2018), leading to enhanced oil recovery. However, the properties of the polymeric solution render it to be very sensitive to changes such as temperature and salinity, thus when exposed to such harsh conditions as frequently present in some oil reservoirs, new problems and limitations arise when using such standard chemicals (Quadri, Shoaib, AlSumaiti & Alhassan, 2015).
Polymers and co-polymers such as PAM, HPAM and sodium acrylate have been successfully used in certain countries like China, India and Oman. Their popularity is associated to the thickening ability, the flocculation and rheological behaviour in the tested formations (Sheng, 2011). In Daqing, China, water-soluble polymers are in use for over 30 years. The introduction of new polymers, co-polymers and other chemicals made Daqing an excellent place for extensive field trials providing significant learnings on the technology performance to the oil and gas industry, including the ability to use alkali to significantly reduce the amount of surfactants needed in an ASP project and associated cost savings. In the Mangala field, India, ASP floods have been extensively implemented allowing the operator to maintain the target production levels. ASP formulations have been also successfully used in both sandstone and carbonate reservoirs in China and Oman.
More recently, Oil and Gas Majors have started to use polymer flooding in offshore areas like the North Sea, where new polymers specially designed for hightemperature and high salinity environments are being deployed (Hinkley & Brown, 2017) In this paper, we provide a critical review of the available polymers for application in high temperature and high salinity reservoirs and summarize aspects to consider for their laboratory screening through a recommended workflow.

Available polymers and suitability for use in harsh environments
In polymer flooding, a water-soluble polymer is added to the injected water during a waterflood. The objective is to increase the viscosity of the water phase to improve the efficiency of the displacement. There are three potential ways in which a polymer flood can make the oil recovery process more efficient: a)by decreasing the water/oil mobility ratio; b)through the effect of polymers on the fractional flow, and c)by diversion of the injected water from zones that are already swept. It is well known that when a polymer is injected into a formation containing a stack of heterogeneous layers, crossflow between the layers improves the polymer allocation so that the vertical sweep efficiency is improved (Sorbie, 1991). Another interesting mechanism is related to the polymer viscoelastic behavior. Due to polymer viscoelastic properties, the normal stress between the oil and the polymer solution results in a larger pull force on the oil droplets or oil films. As a result, oil is pushed and pulled out of dead-end pores or disconnected/stagnant pore regions, resulting in a decrease of the oil saturation (Sheng, 2011 4. Polyacrylamide (PAM): a high molecular weight (>106 g/mol) polymer formed from acrylamide and its derivates. The PAM used in EOR is poly(2-propenamide) with chemical formula -CH 2 CH(CONH 2 )-. It is a non-ionic, water soluble, and biocompatible polymer that can be synthesized as a simple linear chain or as a cross-linked structure. The cross-linked polymer can absorb and retain large amounts of water because the amide groups form strong hydrogen bonds with water molecules. Even though these polymers are called PAM, they are often copolymers of acrylamide and one or more other monomers. One of the most common comonomers is acrylic acid or sodium acrylate. Poly (acrylamide-co-acrylic acid) and its sodium salt are anionic polymers more effective when used as flocculant and water absorbers (polymerdatabase. com).
The four polymers were basically sulfonated polyacrylamide copolymers of AM (acrylamide) with AMPS (2-Acrylamido-2-Methylpropane Sulfonate). The modified co-polymers showed similar rheological behavior to conventional polymers, except one with a unique behavior, a sulfonated polyacrylamide copolymer AM with AMPS, with a 32 mol % sulfonation degree and high molecular weight found to be less sensitive to salinity and temperature for temperatures up to 95°C, which could possibly make it as a better candidate for enhanced oil recovery (EOR) application in high salinity conditions. 6. Salinity Tolerant Polyacrylamide (KYPAM): a copolymer of HPAM that incorporates a small fraction of functional monomers with acrylamide to form comb-like copolymers. These polymers have in their structure an ionic functional group that is tolerant to divalent cations (Luo & Cheng, 1993).
In KYPAM, a functional monomer is introduced, and the side chains have both hydrophilic and hydrophobic groups (Sheng, 2011). The flexible chains are stretched, and the KYPAM viscosity is relatively higher than the HPAM viscosity in more saline waters (Luo, et al., 2002). Laboratory measurements indicate that KYPAM is more temperature tolerant, and it has good shear and thermal stability (Luo, et al., 2002

Polymer laboratory screening
EOR candidate polymers must provide the required rheology at minimal concentration, be thermal, mechanical and chemically stable, and have low adsorption to the rock. In this section, we summarize some of the key aspects to consider when doing a laboratory polymer screening. In general, the series of steps followed for laboratory polymer screening can be summarized in a schematic workflow as shown in Figure 1. It is assumed that a preliminary EOR screening exercise has been completed at a project level taking into account the reservoir properties, field location and logistics, and a calculation of the floodable pore volume with a high-level economic estimation for the lab screening is available. It is a good practice to consider the basic reservoir engineering screening criteria for polymer field application which includes: a) making sure that the candidate reservoir has a reasonable good waterflood performance, b) actual average permeability > 25 mD with no extreme variations, c) sufficient remaining oil saturation (and a good understanding of its distribution), d) water chemistry is known, e) crude oil viscosity < 5,000 cP, f) understanding of the impact of any nearby aquifers, and g) good understanding of available facilities (sufficient injection capacity). Figure 2 shows a recommended laboratory workflow generated based on best practices from the literature and our own experience. To evaluate polymers performance, the recommended approach includes: rock and fluid selection and characterization and the execution of displacement experiments at expected reservoir conditions, here represented by high temperature and salinity.

Step 1: Assessment of the Required Conditions for Lab Screening and Polymer Pre-Screening.
In general, the screening process starts with the selection of commercial available polymers (most laboratories usually test between 5-6 different types of polymers) according to their temperature stability, salinity tolerance, quality of mixing brine, and costs. A series of tests are done to understand the polymer properties at reservoir conditions including evaluation of the fluid rheology based on the response of the viscosity vs. shear thinning (Veerabhadrappa, Urbissinova, Trivedi & Kuru, 2011), evaluation of the molecular weight vs. molecular weight distribution (poly-dispersivity), determination of polymer anionicity, and filtration ratio tests to select the most viable candidates for the formal screening process that includes the polymer performance evaluation through core flood experiments. The results from these tests are analyzed and a candidate ranking is proposed for subsequent evaluation. These tests are done using standard laboratory protocols not discussed in this article.
The conditions at which the injected fluids will be exposed are critical for the success of the process. A good understanding of the reservoir including depth, in-situ pressure, temperature, formation properties like porosity, permeability, pore size distribution, wettability, in-situ fluids play an important role in the process performance. Facilities inputs are also very relevant such as potential injection capacity. If the application is intended to follow a waterflood, it is important to analyze the composition of the produced water for use in the testing.

Step 2. Sample Selection and Rock and Fluids Characterization
Reservoir representative fluids should be used in the tests wherever possible. Live oil is generally preferred; however, if not available, dead oil should be restored at reservoir conditions. Crude properties like viscosity, density, composition at in-situ conditions, total acid number (TAN), SARA and sand and water content (BSW) are in general very useful in the interpretation of the experimental tests. Use of filtered oil is recommended to minimize potential plugging. For the brine attention is needed to make sure it describes the chemistry and properties of the produced water (density, total dissolved solids (TDS), turbidity, pH, and conductivity

Step 3: Polymer Solution Preparation and Properties Evaluation.
For the laboratory tests the polymer solution should always be homogeneous According to the nature of the polymer product for use (fermentation broth, gel or powder) a slightly different mixing method is used to prepare the solution.
Polymer hydration. The preparation of a polymer stock solution, regardless of polymer type, should follow the API RP 63 (1990). According to this standard, the first step is to prepare a stock solution with 5,000 ppm of polymer concentration followed by dilution to obtain the desired polymer concentration. Some recommendations regarding the mixing process to avoid agglomeration of particles are available in the literature (Rashidi, et  Polymer characterization. Even though polymer properties like molecular weight, anionicity, solubility, etc., are provided by the manufacturer, it is always recommended to validate the data through laboratory measurements since commercial product properties may change over time. Polymer anionicity, also known as hydrolysis degree, can be evaluated by C13NMR spectroscopy and C, N elemental analysis (Zurimendi, Guerrero & Leon, 1984) or colloid titration based on the stoichiometric combination of positive and negative colloids where the endpoint is decided by indicators (Terayama, 1952).
Polymer concentration and residual monomer content can be measured using several methods including: a) SEC-MALS with Mw measurement and NMR, b) UV-VIS spectroscopy -a fast and simple method (Gibbons & Örmeci, 2013), c) the start tri-iodine method for water soluble polymers containing primary amide groups (like HPAM) and associative polymers (Scoggins & Miller, 1979), or d) the turbidimetric method that uses a reagent that react with some polymer components (like AMD subunits in PAM/HPAM) to produce insoluble colloids that remain suspended in solution, giving rise to turbidity (Kang, et al., 2014).
For viscosity measurements, a high precision instrument is recommended, like a low shear rheometer equipped with either an ultra-low adapter or small sample adapter. It is important to evaluate the viscosity as a function of polymer concentration and temperature at the optimal shear rate. The protocol associated to the viscosity measurement depends on the type of instrument used; for most common rheometers procedures are described in the API RP 63 standard (1990).
The rheological characterization should be done on selected polymer solutions for a specific concentration and filter ratio tests. In general, viscosity is measured at shear rates ranging from 0.1 to 500 s -1 for concentrations (ppm) ranging from 0 to 5,000. It is also important to evaluate the effect of brine hardness and pH on the viscosity. For the brine hardness, the idea is to quantify the effect of increasing salinity on the viscosity according to the degree of hydrolysis.
Polymer solubility can be assessed by: a) low cost visual determination based on visual detection of when the fluid enters a two phase region, captured as noticeable cloudiness (Wolf, 1985); b) viscosity measurements based on the difference in viscosity between different solutions; c) differential scanning calorimetry -a method that requires high level of expertise for data interpretation; d) gas liquid chromatography has also been used DiPaola-Baranyi & Guillet (1978) due its capability of characterize the polymer-solvent system and to investigate the interaction between polymers and non-solvents; and e) the fluorescence probe approach based on an aggregation-induced emission (AIE) is considered as an accurate method for measuring the solubility parameters of a polymer (Jian, Huang, Wang, Tanh & Yu, 2016).
Filterability is an important test to ensure that a polymer solution is free of aggregates which could lead to formation plugging. The standard procedure to run the tests is described in the API RP 63 Standard (1990) using a high-pressure filter press. Levitt (2009) presented an overview of the filtration procedures, filter size and material adequate according to the polymer type. It is important to consider that filtration ratio tests are in general not conclusive as screening tests when using associative polymers. Previous findings (Alexis, et al., 2016) indicate that AP can show low filter ratio; however, lower polymer concentration is required to generate high resistance factors when used in porous media. For biopolymers, a modified API RP 63 method is used for testing at low pressure to get an acceptable filtration time (Jensen, et al., 2018). In this method the pressure is hold between 1.5 to 3 psi to get 2 to 4 minutes of filtration time with solutions at 50 cP at 10 s -1 .
Another important aspect to consider is the environment where the short/long term thermal stability tests are done, which is recommended to be oxygen free (< 10 ppb) conditions. Tests are conducted at the selected optimal viscosity and polymer solution concentration. The degree of compatibility between the polymer and the brine is assessed by the change in the appearance of the polymer solution as well as the change in viscosity during the aging test. A clear single-phase aqueous solution at both ambient and reservoir temperature are expected for the good polymer candidates, and the polymer viscosity should not decrease significantly during the test duration. Since temperature in general has a significant impact on the polymer behavior, thus the tests should be done at reservoir temperature if possible. Two setups can be used to minimize testing errors: 1) the polymer samples are dispensed into air-tight vials (ampoules) inside of an oxygen-free environment created using a glove box, and periodic visual inspections and viscosity measurements are recorded at selected time intervals, and 2) the solution is transferred into small Hastelloy cylinders with a large enough volume for the viscosity measurements at the specific time points of the thermal stability analysis while all measurements are done in an oxygen-free atmosphere.
Shear stability can be evaluated in two different ways: i) using the API RP 63 (1990) and ii) shearing the polymer solutions at high rpm (usually 30,000) for different time intervals at constant temperature. Viscosity monitoring at each interval allows assessing shear degradation.

Step 4: Setting the Core Initial Conditions
If the field where the polymer flooding is to be applied follows a waterflood, the core sample should be submitted to a similar saturation history by injecting a similar amount of water (in terms of porous volume (PV)) as done in the field starting from reservoir native saturation conditions.

Step 5: Evaluation of Polymer Performance
Polymer performance is evaluated through coreflooding experiments at reservoir conditions. The experimental set-up typically consists in an injection system, transfer cylinders, core holder, backpressure regulator and effluent collector. High precision differential pressure transducers should be used to measure the pressure gradient across the cell. A backpressure regulator (BPR) is frequently placed on the downstream side of the core to help dissolve any air that may remain within porous medium before flooding. It is a good practice to remove the BPR prior the polymer injection to avoid polymer degradation. In addition, the use of pressure taps along the core can provide representative data to assess the polymer behaviour.
Important variables to design the polymer flooding at lab scale are: flow rate, temperature, confining pressure, back pressure, initial water saturation, rock permeability, and effluent properties. Very accurate instruments/sensors are required to assess the values of these parameters. Parameters determined through coreflooding include: permeability, initial water and oil saturations, PV and inaccessible PV, injectivity, RF (resistance factor) and RRF (residual resistance factor), adsorption/retention, slug size, and effluent characteristics.
Injectivity is measured using the pressure drop when the polymer is injected into the rock. The selected polymer must have a good injectivity (minimum pressure-drop) to allow rapid displacement and recovery of oil. The pressure drop is also used to estimate the permeability reduction, and viscosity measurements during flow allows the calculation of RF and RRF. Resistance factors versus polymer solution throughput should be used to analyze the potential of plugging.
Polymer retention is another quantity to pay attention since it delays polymer propagation through the porous formation. High polymer retention can substantially delay oil displacement and thus limit the oil recovery during a polymer flooding. Two types of adsorption/ retention mechanisms need to be considered: i) mechanical retention associated with the relative size of the polymer molecule and the pore dimensions, an irreversible process, and ii) physicochemical adsorption, which is reversible and associated to the chemical and physico-chemical characteristics of the polymer and the rock. Many methods have been reported in the literature to measure polymer retention and inaccessible pore volume ( When evaluating polymer flooding performance for harsh reservoirs, the effluent must be analyzed using the appropriate tools. At least the following tests should be completed: TDS, salinity, dissolved oxygen, pH, conductivity, hardness, polymer concentration, and viscosity. Effluent analysis is used to evaluate the polymer retention, inaccessible pore volume and rheological properties. In addition, the effluent parameters can help to identify issues or problems early on the study before extensive lab work is undertaken. The described workflow works well with most of the standard polymers presented in the previous section. However, when evaluating polymers for use in hostile environments of high temperature and high salinity, further attention is required in particular to the type of instrumentation used in the laboratory. Some aspects to consider include: a. coreflooding system -the wetted parts (coreholder, fluid cylinders, and lines) made from a corrosion resistance material like Hastelloy. The high salt content and the presence of iron in the system could cause corrosion; b. the coreflood system (coreholder, flow lines, capillary viscometer, fluid accumulators, etc.) placed in a constant temperature environment like the one provided by a convection oven.
c. Coreflooding parts like core sleeves and O-rings need to be compatible with the environment. The widely used Viton sleeves and seals made from a fluorocarbon elastomer perform well in the presence of organic fluids like hydrocarbons and other solvents over the temperature range from -7°C to 205°F. For harsh environments the use of AFLAS (a copolymer of tetrafluoroethylene and propylene) material is preferred; d .Injected fluids should be exposed to minimal temperature variations; therefore, fluid accumulators should be placed inside an over and preferably closer to the coreholder.
e. Viscosity measurements are recommended to be done with a capillary viscometer for the rheological evaluation during the polymer flooding f. For effluent collection, it is recommended to use accurate fraction collectors and high precision instruments for evaluation of dissolved oxygen (precision of at least 1 ppb), and accurate titrators for the polymer concentration. We recommend using ion chromatography (IC) instead of an electrode probe to evaluate the salinity when working with polymers exposed to a harsh environment.

Discussion and conclusions
Identifying a polymer that can withstand hightemperature and high-salinity conditions is a major step for a successful polymer-flooding application (Hashmet, AlSumaiti, Qaiser & AlAmeri, 2017).
From the polymers available for EOR, sodium acrylate and polyacrylamide based co-and ter-polymers are found to be stable only under low salinity conditions and in most cases they can resist temperatures up to 70°C. Modified acrylamide co-polymers have improved stability under harsh conditions, however the amount of polymer required to obtain a good recovery is generally too high, around 3 times the amount required for conventional polymers, so their use may be not attractive for commercial applications. Sulfonate base acrylamide co-polymer (ATBS) is an option for temperatures below 105°C. PAMs have showed better high salinity and temperature tolerance than HPAMs which showed relatively good stability only when the dissolved oxygen is extremely low and if divalent cations are minimized. A salinity tolerant polyacrylamide has been developed (KYPAM) but requires additional field testing. Associative polymers seem to be an option for high salinity environments, however further improvement is needed to increase the temperature application limit.
Other polymers like zwitterionic polymers are resistant to high TDS (~ 100 g/L) and can be used as a wettability modifier to increase the recovery factor. Biopolymers like Xanthan gum can resist temperatures up to 100°C with limited tolerance to high salt content could be impacted by bacterial degradation. Scleroglucan has high salinity tolerance up to 200 g/L. These types of polymers are potential candidates for applications in certain types of reservoirs but they all need to be field tested.
A more promising candidate for harsh reservoir is a synthetic polymer NVP-free with ATBS content due its thermal stability up to 140°C and salinity tolerance (up to 220 g/L) tested for carbonates with a good performance. We expect future work to continue on the improvement of the polymer properties.
The laboratory screening process typically starts after a pre-screening phase that provides the required data to understand the behavior of the polymers at the tested conditions. It is important to consider the polymer chemical structure since the rheological properties are affected by the chemical structure and the external parameters.
When screening for the polymers under harsh conditions important points to pay attention are: a) impact of salt -the viscosity of the polymer should decrease as the salt concentration increase, b) analyze the polymer rheology since a thermal degradation may occur at high temperature, c) since different polymers display different behavior when they are mixed with brine it is recommended to use the hydration method suggested by the vendor, and d) high salt contents result in a strong molecular interaction in the polymer solution, and when the salinity is very high the solubility of the polymer might be compromised, forming a different structure.
Regarding the polymer performance careful evaluation of the results is required before proceeding to the polymer ranking and selection. Some experimental results could be difficult to interpret. For example, higher values of RF and RRF factors could be attributed to geltype effects in aqueous solution, resulting in an increase in mobility retardation. Also, when Fe +2 is present with dissolved oxygen, the viscosity of the polymers can decrease due free radicals attack (Fenton reaction) even at low temperatures (25°C) making difficult to understand the viscosity behavior (Pope, et al., 2014). For this reason, we recommend using all available results from the polymer ranking exercise rather than discarding a particular polymer based on the result from one single test. Just as an example, associative polymers are sometimes rejected based on the outcome from the filtration ratio test; however, these polymers show reasonable good performance in core flood experiments, which are more representative of what may occur in the field application.
We emphasize that for carbonates in harsh reservoirs the restoration is particularly important since the carbonate rock can become more oil-wet when exposed to increased concentration of divalent cations in the brine. Thus, aging in reservoir oil aims to preserve injectivity and reduce the retention on the rock surface (Dupuis, et al., 2017).
Finally our message can be summarized as: To be successful in a polymer injection project it is important to set clear objectives, gather the required reservoir information, have the resources to conduct all the required tests, perform careful QA/QC of the results, use best practices to obtain high quality data, to document properly, and to use all the available information and results to understand the polymer behaviour before making a final decision on the ranking of the polymers.