Rock Lithology-Based Laboratory Protocols and Best Practices for Polymer Screening for EOR Application in Conventional and Harsh Reservoirs

Abstract

EOR applications have seen a recent shift in focus from onshore use in sandstone formations to more complex environments, such as carbonates and reservoirs in offshore settings. This explains the attention given thus far to develop EOR screening criteria mainly for use in sandstone reservoirs, where significant success has been observed. Screening of chemical EOR applications is mostly centered on the evaluation and characterization of fluids and some formation properties without explicit consideration of the formation lithology in some cases. Standardized lithology-based laboratory protocols are required to avoid cost overruns on screening and the design of fluid formulations for specific use in a particular reservoir. Such is the case of carbonates, typically highly heterogenous formations often found in high salinity and temperature conditions, where most available chemicals have limited applicability, and where standard screening protocols are not reliable or lack proper detection limits. In this chapter, we present an integrated laboratory workflow for polymer screening with recommended protocols based on formation lithology. It was derived from successful polymer application in the O&G industry and our own experimental work over the last two decades. Its use results in better quality data with time savings, contributing to a better understanding of the field application.

1. Introduction

Most EOR screening criteria focus on sandstone onshore applications, where the cost of implementation allows for their use. As a result, extensive experience has been gained through the years in those reservoirs. More recently, the attention has moved to more complex environments, such as onshore carbonates and reservoirs in offshore settings, where the size of the price seems attractive enough to consider EOR as part of the field development [1, 2].

For a successful implementation of chemical EOR in different types of lithologies and depositional settings, standardized laboratory protocols are required to avoid cost overruns on screening, and the design of fluid formulations for specific use in a particular reservoir. The screening of polymers for use in EOR application for carbonates is particularly challenging since they are highly heterogenous formations frequently found in relatively high temperature and high salinity conditions, where most of the available chemicals for EOR have limited applicability. The standard protocols for screening are not reliable due to the typical detection limits making it difficult to understand which formulations work best in those complex environments.

Even though there is extensive literature on polymer applications for EOR, it is noticed that there is no consistency in the way polymers are screened in the laboratory for their use, making it difficult to even compare products from different vendors [3]. Some of the tests do not consider the formation lithology and the potential influence of mineralogy on the polymer screening process. These elements reflect a clear need for an integrated workflow for polymer laboratory screening that explicitly considers the rock lithology and reservoir conditions. Such a workflow would be very relevant for applications in reservoirs exposed to high temperature and high salinity.

In this chapter, we provide an overview of the key steps of a laboratory workflow and the recommended protocols for the laboratory measurements according to the formation lithology where the polymer will be used. The workflow has been derived based on the successful application of polymers in the oil and gas industry, and our own experimental work over the last two decades. The use of an integrated workflow with standardized laboratory protocols helps with the screening process not only avoiding repeating tests that frequently are inconclusive, but also provides better quality data saving time and allowing for a better understanding of the potential field application.

The different steps of the proposed workflow are presented in detail and illustrated with the use of reservoir samples to demonstrate the limitations of the standard experimental protocols used, and a discussion on the relevant best practices industry wide from successful applications in the field. The emphasis is given to the need to move away from “model” lab conditions by using reservoir rock and fluid samples as best practices, the recommendation to execute the tests at reservoir pressure and temperature conditions on restored cores, the use of representative saturation conditions, and the value of considering a variety of potential testing scenarios that reflect the expected changes that the polymer solutions will experience during their use in the field application.

Polymers have been used to increase the areal and vertical sweep efficiency of in situ hydrocarbons in the process of polymer flooding to improve recovery. Due to the high cost of chemicals and trending low oil prices, it is essential to optimize polymer flooding strategies to shorten the polymer injection time and also maximize efficiency to keep the operation economically feasible, especially in carbonate and offshore oil fields.

Despite having many successful polymer floods [3], field application of polymer flooding still faces several challenges, in particular for offshore EOR projects:

1. Reservoir and Wells: Chemicals suitable for different reservoir lithologies, presence of heterogeneities such as fractures/faults, high-permeability layers (as in Bohai [1]), high-salinity formation water, high-viscosity crude oil, distribution of residual oil distribution, large well spacing, and optimal well patterns [1, 2, 3].

2. Water source: Use of freshwater versus high salinity water [1].

3. Available working space: typically, there is limited space in the offshore platform for the equipment to prepare polymer solution, and the injection system needs to be compact, flexible, and efficient [1].

4. Environmental requirements that for offshore implementations are high as the produced fluid from polymer flooding needs to meet the standards set by government/regulatory agencies [1, 3].

There is a huge difference between polymer injection in offshore and onshore fields including the timeline, type of equipment to measure critical parameters at high temperature and pressure, and the lack of laboratory standards to evaluate the performance of polymers for offshore application [1]. In the last two decades we have seen the result from R&D work, field trials, and applications of offshore chemical EOR techniques translated into equipment and techniques that enabled offshore EOR, including high-efficiency driving agents, platform polymer injection distribution systems, produced fluid treatment technology, and a variety of methods for performance evaluation of early-stage polymer flooding [1, 4].

2. Types of polymers for EOR applications

Even though there are different types of polymers available in the market for EOR applications, including powder, liquid, and emulsion polymers, selecting the right type according to the reservoir lithology, properties, and conditions is not an easy task.

The most common polymers used in field applications are anionic polyacrylamide, hydrolyzed polyacrylamide (HPAM), and co-polymers, such as sodium acrylate. The addition of functional monomers is a way to modify them for specific applications. For example, N-vinyl pyrrolidone has been proven effective to improve the thermal stability and salt tolerance of conventional polymers [4, 5]. Biopolymers are also used; however, they have limitations due to environmental concerns and operational costs related to degradation by bacteria resulting in the need for frequent biocide treatment. Schizophyllan is in use in the Bockstedt field in the North Sea since 2006 for its stability for temperatures up to 130°C while being environmentally friendly [6]. Other polymers, such as the one proposed by Skauge [7] for use at low concentration and not field tested yet, are generated by a crosslinking reaction between aluminum and HPAM.

Chang [8] reported results from an evaluation of polymer flood in 16 USA field cases with only one done on a limestone formation where polyacrylamide polymers and Xanthan Gum were used. Literature data on 72 polymer field applications, including six offshore projects, show that most projects used HPAM (92%) and biopolymers. Only one project used an associative polymer in Bohai Bay, China [9]. The emulsion type of HPAM has been the preferred way of transportation except for some fields (Dalia, Bohai and SZ36-1) where the powder form was used.

Recent review work summarizes the available polymers for use in high temperature and high salinity reservoirs [10, 11]. These polymers are mainly based on acrylamide. Modified acrylamide co-polymers and polyacrylamides have shown better tolerance to high salinity and temperature than HPAMs. For example, sulfonate-based acrylamide polymer works well for temperatures up to 105^°C.

Associative polymers seem to be an option for high salinity environments [12, 13]. A promising candidate for use in carbonates is the synthetic polymer N-vinylpyrrolidone-free with acrylamide tertiary butyl sulfonic acid, which shows thermal stability up to 140^°C and salinity tolerance up to 220 g/l [14].

Candidate polymers for EOR applications should meet the following requirements [3, 11]—(a) high viscosity at reservoir conditions, (b) low impact on injectivity—thus good solubility and filterability, (c) stability at reservoir conditions (temperature, salinity, pressure, and hardness), (d) compatibility with injection chemicals and in situ fluids, (e) low adsorption, (f) friendly to the environment (including CO₂ footprint), (g) low impact on water separation processes.

The actual presentation of the polymer, either in powder or emulsion form is not so critical for the actual field application, since the polymer chemistry can be achieved in any of these presentations. What is critical is the screening process they follow to determine the most suitable candidates.

The following points have been reported as relevant when selecting the polymer presentation:

1. Polymers in powder form are popular for onshore use, whereas liquid polymers are considered for use in remote locations, such as offshore reservoirs and more hostile environments

2. Preparation of the emulsion polymer requires more attention than its use in powder form since it behaves like a multi-component system [15].

3. The polymer solution from powder is prepared on-site, thus it is easier to use compared to the emulsion type of polymer [15, 16].

4. The equipment footprint for dissolution of emulsion polymers is smaller than the required for powders. Its transportation is also easier. In general, it is challenging to use powders for offshore applications [15].

5. Since the polymer powders are designed to cover a wider range of conditions, there is no need to adapt the formulation to the actual reservoir conditions. In the case of the emulsion type, the surfactant package must be adapted to the reservoir brine characteristics (temperature and salinity) to allow a perfect release of the macromolecules and a good dispersion of the oil droplets avoiding injectivity issues [17].

6. Emulsion polymers require less time to dilute compared to powders (10 min by phase inversion for emulsions vs. 120 min for powders) [17].

7. Powder polymers seem to be more thermal stable than emulsion polymers [17].

8. Emulsion type of polymers has a lower active concentration range (∼30–48%) requiring larger volumes for transportation. Powder forms active concentration can be up to 100%, thus lower volumes are required to be transported for field application [18].

9. In terms of oil recovery percentage and pressure response, no significant differences have been observed between both types of polymers [16, 18].

3. Workflow for laboratory screening

Following oil and gas best practices for laboratory polymer evaluation [3, 11, 15, 19, 20, 21, 22, 23, 24], a consistent workflow is proposed to select polymers for EOR applications, as illustrated schematically in Figure 1.

Figure 1.

Overview of the proposed workflow for polymer screening.

The first step relates to the pre-selection of commercially available polymers. This is done based on a comprehensive list of key reservoir parameters to be shared with the polymer’s providers. The minimum set of parameters required for the pre-selection of a polymer for lab screening includes reservoir temperature, rock lithology (carbonate, sandstone, shale, etc.), formation brine composition and properties (salinity, pH, total dissolved solids (TDS), R+), oil properties (API, Density, TAN and water content).

Once the pre-selected polymers are received in the lab, the polymers are prepared (dissolved in reservoir brine) (Step 2) and quality checked by evaluation of the amount of insoluble particles (<0.01%) and viscosity measurement at reservoir temperature (Step 3). Polymers that pass the Quality Check (QC) step are considered for the next screening steps (Steps 4 and 5). It is recommended that polymer characterization and performance evaluation to be done by an independent laboratory and not by the polymer provider.

In the next sub-sections, the recommended tests are presented and discussed.

3.1 Preparation of polymer solutions

Polymer transport and preparation can be challenging for a chemical EOR project. Lab analysis can help to support the field implementation. The preparation of all-polymer stock solutions, regardless of polymer type, follows the well-known best practices in the industry [15, 19, 20, 21, 22].

Powder hydrolyzed polyacrylamide (HPAM) and polyacrylamides (PAM) type of polymers stock solutions are prepared at a concentration of 5000 ppm. It is recommended the solutions be prepared inside a glove box previously evacuated and purged with nitrogen (three times) to remove all oxygen. With the brine under stirring at 400 rpm with an overhead mixer, the polymer is slowly introduced to avoid the formation of fisheyes (over a period of 30 s). The mixture is stirred for 5 min at full vortex. Additional stirring up to 120 min is required in some cases for full solution homogenization.

In the case of the emulsion type polymers according to the mechanical dissolution conditions, the time to dissolve it may vary from a few seconds to a few minutes. Emulsions are usually most effective when the dissolving operation is carried out continuously. It is important to observe a final concentration in a solution of approximately 5 g/l of active material. The emulsion solution is injected using a syringe into the brine, and the entire emulsion volume is added as quickly as possible. After 10 min, the solution should be homogeneous with light color and viscous appearance.

As a protective measure, additional chemicals can be added to prevent polymer degradation due to the presence of oxygen and iron, and bacteria. If that is the case, it is important to verify the final solution is properly homogenized [15, 22].

Polymer mixing has been recognized by operators as an important step in polymer screening, and specific laboratory mixing protocols have been proposed for use with liquid polymers. The wellness of the mixing is described by the specific mixing energy parameter [25] that helps to upscale data from lab to field. It can be also applied for the mixing of powder polymers.

3.2 Polymer stock solution filtration and dilution

The polymer stock solution must be filtered before its use to remove any aggregates present. It is recommended to filter the stock solution through a 5 μm polycarbonate filter. In most cases, polymers are filtered using a high-pressure filter assembly. A pressure differential of 15 psi is typically obtained when using nitrogen or argon. Once the filtration step is complete, the remaining fluid is discarded.

Modified filtration methods are required when working with low permeability carbonate rocks before making rheology and injectivity measurements [26].

To achieve the desired polymer concentration, the next step is to dilute the prepared and filtered stock solution. From the stock solution in the globe box, brine is gradually introduced, and the solution is continuously stirred for another hour or so to completely homogenize the solution.

3.3 Polymer-brine compatibility

Step 4 of the laboratory screening workflow for both carbonates and sandstones formations regardless of reservoir conditions starts with the evaluation of the compatibility between the polymer and reservoir brines (formation and injection). The best practice is to do the test in both brine. If there is a need to speed up the study, the test with formation water can be skipped for sandstones [11, 22].

Polymer-brine compatibility is evaluated at a fixed solution concentration and reservoir temperature. The solution is placed into a temperature-resistant bottle in an oven at the required temperature for a period of at least 21 days. The bottles are removed from the oven daily. The appearance of the solution is observed, and the viscosity for the corresponding bottle is measured. Any change should be registered.

For quality assurance purposes it is recommended to do the test on duplicate samples. If the results are not similar for both samples, the procedure must be repeated. After mixing, the solutions are visually analyzed for solubility and classified using the following criteria:

• Compatible, Clear, or Soluble (C): Transparent clear single-phase solution observed. Changes in Viscosity <1% over a period of 21 days.

• Non-Compatible or Insoluble (NC): Two distinct phases or precipitates are observed.

Figure 2 provides an example of compatibility for three different polymers dissolved in the same brine and aged at the same temperature. The solution with the best solubility is the one that shows the smaller change in viscosity over a period of 21 days.

Figure 2.

Example of compatible and non-compatible polymer-brine solutions.

3.4 Polymer solution properties

After the brine-polymer compatibility is evaluated, a series of tests are performed to select the potential candidates for a field application including filterability, molecular weight, chemical degradation, viscosity and density, screen factor, static adsorption, and thermal stability at reservoir temperature, as described below.

3.4.1 Polymer filterability

The filter ratio test is important to ensure that a polymer solution is free of aggregates which could lead to formation plugging [2, 11]. Filterability of polymers can be affected by the quality of the injection water, fluid incompatibilities, bacterial contamination, polymer chemistry, and stability. The best practice is to test both in formation and injection brines.

It is recommended to follow the standard protocols as reported in the literature [22, 23, 25, 26, 27, 28, 29, 30], where filter ratios are evaluated at two polymer concentrations, usually 1000 and 2000 ppm.

A given volume (V₁) of the diluted polymer solution is introduced into a high-pressure filter apparatus loaded with a 0.1–5 μm polycarbonate filter. A pressure drop of 15 psi is applied and maintained during the test using nitrogen or argon gas making sure the flow rate remains constant to avoid the formation of aggregates. The time required to filter specific volumes of polymer solution (V₂, V₃) is recorded. The test is concluded once the total V₁ solution volume has been filtered. The filter ratio (FR) is calculated using Eq. (1).

$$\mathit{FR}=\frac{V_1-V_2}{V_2-V_3}$$E1

After the test, the filter is carefully inspected to see if any remaining polymer micro-gel is present due to improper hydration. A polymer solution with FR < 1.2 is considered acceptable for a rheological test [31]. The test is repeated using a 2000-ppm concentration for polymers with a FR < 1.2.

3.4.2 Polymer molecular weight

Even though the vendors provide this information with their products, it is a good practice to validate it (if possible). Several methods are widely used to evaluate MW, including Size Exclusion Chromatography [32], Gel Permeation Chromatography [33], Laser Desorption/Ionization Time-of-flight Mass Spectrometry [34], and Nuclear Magnetic Resonance [35]. Field flow fractionation [36] is another technique for MW measurement that is gaining popularity in the polymer user community. Calibration with well-characterized samples is required for accurate MW determination.

3.4.3 Chemical degradation

Polymers can be broken down into monomers in a process known as hydrolysis, a reaction done in the presence of water. Chemical degradation is evaluated through the degree of hydrolysis. Accepted values for polymer degree of hydrolysis are in the range of 15% and 33% [28, 37, 38]. Optimum values for polymer hydrolysis degree are in the range 25 +/− 5% [2, 11].

Quantification of the degree of hydrolysis for a polymer is an important step both before and after a polymer flood. It is important to consider that the degree and rate of hydrolysis increase with temperature and is a linear function of pH in non-neutral-pH solutions. For hydrolysis degrees greater than 30% and in the presence of calcium cations, PAM polymers precipitate with additional viscosity losses [38, 39].

The degree of hydrolysis can be evaluated by C13NMR spectroscopy and C, N elemental analysis [24] or by colloid titration based on the stoichiometric combination of positive and negative colloids where the endpoint is decided by indicators [40]. Colloidal titration allows for simple and accurate verification of a polymer’s degree of hydrolysis. The polymer in solution can be precipitated, concentrated, and analyzed just like a dry polymer powder to assess if the polymer’s degree of hydrolysis was altered during the flood.

Polymers can also be chemically degraded by redox reactions in the presence of contaminants, such as oxygen or iron, resulting in the formation of free radicals, that impact the polymer properties. In some cases, these unwanted effects can be reduced by using radical scavengers, chelating agents, or oxygen scavengers [5, 15, 41].

3.4.4 Viscosity, screen factor, and density of polymer solutions

It is important to evaluate the polymer viscosity and density as a function of its concentration and temperature at the optimal shear rate. The measurements should be performed using high precision instruments, such as low shear rheometers equipped with either ultra-low adapters or small sample adapters for viscosity, and high-temperature densitometers. The protocol associated with the viscosity and density measurement depends on the type of instrument used [11, 22].

It is recommended to measure viscosity at shear rates ranging from 0.1 to 500 s⁻¹ for concentrations in the range of 0–5000 ppm. Density should be measured at reservoir temperature. The effect of brine salinity and pH should be assessed to quantify the decrease in viscosity with a salinity increase. Viscosity measurements are also used to evaluate the mechanical (shear) degradation of the polymer by shearing the polymer solutions at high rpm for different time intervals at a constant temperature. Viscosity monitoring at each interval allows assessing the mechanical degradation [3, 42].

The screen factor (SF), defined as the ratio of the flowing time of the polymer solution through the screen viscometer to the flowing time of the same volume of solvent, allows to measure the viscoelastic response of the polymer determining its ability to sustain sudden elongational deformation. It is considered as an optional test since it is more sensitive than the intrinsic viscosity to differences in molecular weight and molecular weight distribution.

As stated by Lim et al. [43], a major disadvantage of the intrinsic-viscosity measurement is the associated time-consuming experiments. This lengthy process must be carried out if meaningful results are to be obtained for high-molecular-weight polymers. SF measurements offer a simple, rapid characterization method for dilute polymer solutions that correlate well with end-use performance.

3.4.5 Static adsorption of polymer solutions

A key parameter in the application of polymers for chemical flood is the loss of polymer due to adsorption to the formation rock [3, 44, 45], and more in general, its retention during flow in the porous medium that can prevent proper oil displacement impacting the hydrocarbon recovery.

Since polymers are characterized by having high molecular weights and long chains typically containing many polar groups, they will tend to attach to the available polar points on the rock surface [46]. The adsorption can be severe for situations where large surface areas are available to the polymer. It is irreversible and can result in lower oil recovery [38, 47].

There are large differences (10–30%) in the way the adsorption of polymers is measured, either by static adsorption test or by the dynamic retention in a core or pack as shown by Lakatos et al. [48]. The differences are the result of changes in the specific surface area and the accessibility of certain regions of the pore space. Typically, the adsorption determined by the bulk static method is greater than the one determined by dynamic flow conditions [48].

The static adsorption test is done on crushed formation cores resulting in much higher adsorption levels, as more surface area is accessible to the polymer. The maximum accepted value for static adsorption is around 200 μg/g [47, 48].

A practical method used to quantify polymer adsorption is the approach suggested by Chiappa et al. [49], where for a given volume (V) of solution the polymer concentration is measured before (C_o) and after (C_e) exposure to formation rock. Polymer adsorption is calculated by dividing the loss of mass from the solution by the weight of the exposed rock (W).

$$q_{\mathrm{abs}}=\frac{V\left(C_o-C_e\right)}{W}$$E2

Some criticisms of this method have been reported including—(a) it relies heavily on only two polymer concentration measurements, so errors in those measurements have a substantial impact on the calculated adsorption value [50]. (b) As the rock is pulverized, the surface area and minerals are exposed, this condition is not available during dynamic experiments (polymer solutions flowing through the porous rock) [38, 39, 50]. (c) The method cannot assess mechanically entrapped polymer [50, 51].

Polymer adsorption is highly related to the rock mineralogy and the presence of clays. In general, it is dominated by nanoclay and nanosilica [52]. Higher adsorption is observed in carbonates than in sandstones.

3.4.6 Thermal and biological stability of polymer solutions

The assessment of the long-term thermal stability of the polymer solution should be done with the polymer solution diluted to its target viscosity in oxygen-free environments (< 10 ppb) at the reservoir target temperature and in sealed glass ampoules. Details on the experimental setup are given by Araujo and Araujo [42].

The primary purpose of this test is to verify that the polymer remains stable in brine for 90 days. Stability in this context means the polymer solution remains clear and its viscosity does not decrease drastically during the aging period. Accepted criteria can be stated as follow: (i) Clear single-phase solution at both ambient and reservoir temperature observed; and (ii) viscosity changes <5% over the 90-day period, as shown in Figure 3.

Figure 3.

Example of thermal stability results for the polymers shown in Figure 2.

Thermal stability is expressed as the percentage of the viscosity retained after a chosen period of exposure to a higher temperature.

The biological stability of a polymer solution can be tested in a similar way as the thermal stability by measuring the viscosity loss of the solution as a function of time [53]. An alternative method is to observe bacteria growth using light scattering and other methods or to evaluate the bacteria metabolism [53]. Testing should also include the effectiveness of biocide.

3.5 Evaluation of the polymer performance

3.5.1 Rock and fluids preparation

To evaluate the performance of the preselected polymers, the first step is to select rock samples for testing and make sure reservoir fluids are available or could be reproduced in the laboratory. It is recommended to have representative rock samples based on rock and fluid characterization best practices [3, 11, 42, 54]. This is especially important since lithology differences can impact polymer performance.

Representative reservoir fluids should be used in all lab testing. In practice, the use of “live oil” could be limited by the quality and availability of reservoir oil samples. If this happens either bottom-hole samples or dead crude oil can be used or recombined with gas based on PVT data to properly mimic the in situ conditions [42]. After deciding which oil to use, it is important to determine relevant crude properties including viscosity, density, total acid number (TAN), SARA, and sand & water content (BSW).

All reservoir oil (whether live, recombined, or dead) must be filtered and treated to remove any contaminants (such as sand particles and water droplets) prior to making any measurements. For the filtration, the filter size needs to be considered especially for low-permeability samples. A good understanding of reservoir lithology provides steer on the filter selection. Standard filter sizes are 10, 3, and 0.45 μm. If the average mean pore throat size is smaller than these filter sizes, the selected core plug sample will be acting as a further filter during testing, with the potential risk of plugging.

A suitable oil sample can be prepared from dead oil and PVT data. In the process, the dead oil is mixed with a solvent to reduce the viscosity to its target value. The following procedure is recommended for its preparation: (i) Heat the dead oil in the original container (or cylinder) to reservoir temperature; (ii) shake the container vigorously to homogenize the oil and pour it into a beaker; (iii) stir the oil using overhead stirrer and add solvent (toluene), stir for a minimum of 3 hours; (iv) transfer the mixture into a fluid accumulator, and allow it to equilibrate in an oven in a vertical position for a half-day, then check the viscosity; (v) if the viscosity is too low, continue stirring to allow the solvent to evaporate, if the viscosity is too high, add solvent to the mixture. When working at a high temperature (that could lead to solvent evaporation), it is important to annotate the initial and final volumes to ensure there is solvent present at the end of the mixing step.

The laboratory brine is typically prepared using the reservoir formation and produced waters chemistry. Once prepared the brine properties are determined using the standard protocols. Recommended properties include evaluation of density, total dissolved solids (TDS), turbidity, pH, and conductivity. If the brine is not used immediately, it should be handled and stored following the procedure described by McPhee et al. [54].

Regarding the rock samples, it is important to use samples with the appropriate lithology and to consider the formation heterogeneity to make sure the selected samples are representative. For complex lithologies, such as turbidites and carbonates, it is recommended to use multiple samples rather than focusing on just one. Once a decision is made, the core samples (typically plugs or full core sections) are cleaned to remove any residual fluids and/or solids present. This is generally done via flushing, flowing, or solvent contact. The literature recommends using at least two of these methods for an effective cleaning [54]. Solvent selection is done based on lithology [54, 55]. Once the samples are clean, they are dried using an appropriate method, based again on the lithology, with special attention to mineral composition (frequently the drying is done under vacuum, or in a humidity-controlled environment). Drying is continued until no changes in sample weight are observed to make sure all interstitial water is removed.

It is very important to determine some rock properties prior to exposure of the rock to the polymer solution. It is recommended to evaluate the porosity, permeability, pore size distribution, wettability, and to have a mineralogy analysis. It is recommended to use core samples of at least seven in length since end effects can add uncertainty to the flow properties.

To closely relate to the actual reservoir conditions the wettability of the core samples should be restored via aging [54, 56]. This is done by exposing the clean rock sample to the reservoir fluids at the expected reservoir conditions. This step is time-consuming and thus not performed by many laboratories; however, it is very important for the understanding of the test results. Additional details are given in Ref. [54].

3.5.2 Coreflood testing

The primary purpose of the core flooding testing is to compare the selected polymers in terms of their propagation behavior through the porous formation including relative retention, permeability reduction, and impact on the pressure response to gather data for use in simulation models for EOR project design and field-testing planning.

During the coreflood test, the comparison of the polymer propagation is done via differential pressure measurement. It is recommended to measure the pressure gradient across various sections of the core and over the entire sample, and that the data show indications of no plugging or filtration effects of the injected polymer solution. The steady-state pressure differential should be stable and not change with an additional polymer injection.

Properties that are determined from core flooding tests include:

1. Pore volume (PV) and inaccessible pore volume (IAPV).

2. Mobility reduction or resistance factor (RF): defined as the apparent viscosity of the polymer solution during its flow through the porous formation. It is calculated as the ratio of the pressure drop across the sample during polymer injection and the one measured while flowing brine under steady-state conditions.

3. Polymer retention: informs the extent of the polymer propagation through the rock. Many methods are available to measure polymer retention including static and dynamic measurements [22, 49, 51, 57]. It is important to keep in mind that several factors may affect polymer retention including polymer type (cationic, anionic, and amphoteric), the degree of hydrolysis, the polymer and brine concentrations used, brine salinity, oil saturation, wettability [42], rock lithology and properties like permeability and pore size distribution. For details refer to Manichand and Seright [51]. Retention values measured at field scale range from 7 to 150 μg of polymer/cc of bulk volume with an acceptable retention level around 20 μg/cm³ [45]. It is recommended that polymer retention be less than 100 ± 25 μg/g of rock.

4. Residual resistance factor (RRF) is defined as the loss of permeability given as the ratio of mobility of initial injected water to the mobility of injected water behind the polymer solution. It could be due to several mechanisms, such as polymer adsorption, mechanical retention of polymers in the pore space, and any other condition like precipitation that could retain the polymer formation (in particular when in presence of divalent cations in the formation water). It is determined as the ratio of the pressure differential post polymer injection and with brine at the same conditions.

Figure 4 shows the steps for core flooding testing to simulate polymer floods. The first step is to prepare the fluids (synthetic formation brine and injection brines) and restore the oil at reservoir conditions of temperature and pressure. The polymer solution is prepared at the target concentration defined by the rheology tests. Once prepared, the solutions are filtered, and the viscosity is measured before and after filtration at a shear rate of 7.34 s⁻¹. Then the polymer solution, brine, and oil are let to equilibrate (in an oven) at the reservoir temperature and pressure.

Figure 4.

General workflow for coreflooding testing using polymer.

Simultaneously with the fluid preparation, the rock samples are cleaned, characterized, and restored according to the methods described earlier. After wettability restoration, two coreflood tests are performed:

1. Single-Phase test to determine the porous volume (PV), inaccessible pore volume (IAPV), injectivity response, brine permeability, polymer retention, resistance factor (RF), residual resistance factor (RRF), and the effluent characteristics including viscosity, pH, and polymer concentration in the effluent.

2. Two-Phase test to evaluate the retention of the polymer in the presence of oil, additional recovery from the polymer injection, and to optimize the polymer slug size.

A summary of the best practices for running the coreflood is given by Araujo and Araujo [3, 11, 42]. Two twin/similar samples are required for the single- and two-phase coreflooding tests for a proper assessment of the polymer performance.

3.5.2.1 Single phase test

Once the coreflood apparatus is setup and ready for testing with a new sample, the pressure is checked, and all lines are purged with brine before saturating the sample. The oven and fluid accumulators must be at reservoir temperature and the core holder at reservoir pressure. To measure the porous volume of the rock sample it is recommended to use a tracer test with a salt such as KCl [42]. After the test is complete, the system is flushed with brine to remove any residual KCl. The proposed single-phase test follows a modified Osterloh procedure [58]:

1. The core sample is fully saturated with formation brine.

2. Brine is injected into the core at different rates (1–32 ft./day) to determine brine permeability.

3. Polymer solution (at least 2PV) is injected into the core with a tracer using a flow rate selected from brine permeability testing (in most cases 2 ft./day).

4. Samples are collected in 4 ml increments, and the polymer and tracer (if used) concentrations are measured.

5. After the effluent concentrations for both the polymer and tracer reach the injected concentration levels, several PVs of brine are injected to displace the mobile polymer and the residual tracer.

6. The total brine injected is recorded and permeability reduction (resistance factor, RF) is calculated. The resistance factor is determined using Eq. (3), where ∆P Polymer (Q) is the pressure differential measured when injecting polymer at rate Q, and ∆P Brine (Q) is the pressure differential measured when injecting a brine at the same rate Q. It is a good practice to check that the resistance factor calculated for the entire core is similar to the one for sections of the core.

$$\mathit{RF}=\frac{\left(k/\mathrm{\mu }\right)\text{brine}}{\left(k/\mathrm{\mu }\right)\text{polymer}}=\frac{\mathrm{\Delta }P\text{Polymer}\left(Q\right)}{\mathrm{\Delta }P\text{Brine}\left(Q\right)}$$E3

1. 7. After calculating RF, a second polymer flood is performed to estimate IAPV and quantify the amount of polymer retained in the core sample. It is important to keep in mind that polymer adsorption during the second polymer flood is very small, thus the polymer can be used as a tracer.

   IAPV is determined as the difference in the areas under the polymer breakout curve and the tracer breakout curve using Eq. (4) [51, 57, 58].

$$\mathit{\text{IAPV}}=\sum \left[\left(\frac{C_p}{C_{\mathit{pi}}}x∆\mathit{PV}\right)-\left(\frac{C_t}{C_{\mathit{ti}}}x∆\mathit{PV}\right)\right]$$E4

where C_p is the polymer concentration in the effluent, C_t is the tracer concentration in the effluent, C_pi is the injected polymer concentration, C_ti is the injected tracer concentration, PV is the pore volume equivalent and ΔPV is the pore-volume increment.

1. 8. The residual resistance factor (RRF) is determined using Eq. (5) [57, 58].

$$\mathit{RRF}=\frac{\mathrm{\Delta }P\text{water after Polymer Flooding}\left(Q\right)}{\mathrm{\Delta }P\text{water before Polymer Flooding}\left(Q\right)}$$E5

RRF shows how much reduction of permeability has occurred after polymer flooding in rock due to polymer molecules adsorption.

Polymer concentration can be measured by ICP-OES, the starch iodide method [59], and from viscosity via a calibration curve [60].

The experiment is repeated using another polymer solution (higher concentration) to determine RF, and at the end of the test, after injection of multiple PVs of brine, the RRF is calculated. Viscosity measurements done using an inline capillary viscometer can also be used to determine RF and RRF through viscosity measurements during the polymer injection [60]. Using the RF versus polymer throughput curves the potential plugging during the flooding can be estimated [57].

The injectivity is evaluated during the polymer flow by observing the trend of the pressure drop across the core. Since injectivity is one of the polymer selection criteria good candidates are formulations with associated low-pressure drop. Magnitude of the pressure differential across the sample varies according to lithology, with higher values for tight formations [42]. It is important to keep in mind that polymer mobility reduction could be observed at low injection rates attributed to polymer shear thinning behavior due to accumulation in the core.

Seright et al. [57] give a good discussion on the range of typical values of RF and RRF comparing scenarios with varying conditions (lithology, temperature, salinity, etc.).

3.5.2.2 Two-phase test

Using the second twin sample, the porous volume and the brine permeability are first determined. The oil permeability is determined next, which is done by injecting at least 2 PV of oil for at least three to five flow rates typically in the range of 1–64 ft./day. At those conditions, the sample is then aged for about 40 days to allow wettability restoration.

Once the sample is restored, a batch of oil is injected and the initial oil saturation (S_oi) is calculated by mass balance using Eq. (6).

$$S_{\mathit{oi}}=\frac{V_w}{\mathit{PV}}$$E6

where V_w is the volume of the produced water, and PV is the pore volume of the core sample. The irreducible water saturation (S_wr) is calculated using Eq. (7).

$$S_{\mathit{wr}}=1-S_{\mathit{oi}}$$E7

Effective oil permeability is calculated using Darcy’s equation with the measured pressure drop and the volumetric flow rate, and the end-point oil relative permeability as the ratio of the effective oil permeability (k_o) to the brine permeability (k_b) as shown in Eq. (8).

$$k_{\mathit{ro}}^o=\frac{k_o}{k_b}$$E8

Once these properties are evaluated the flooding sequence starts with a waterflood for at least 3 PV making sure reaching steady-state conditions. The objective of this step is to displace and produce the mobile oil and determine the oil saturation after waterflood. The oil saturation after the waterflood step is referred to as the remaining oil saturation and it is not necessarily the residual oil saturation. The volume of oil produced during the waterflood is recorded and used to calculate the oil saturation at the end of the waterflood. For that purpose, a fractional effluent collector is used to gather effluents in glass tubes to calculate the oil recovery.

The remaining oil saturation after waterflooding S_orw is calculated using Eq. (9).

$$S_{\mathit{orw}}=\frac{\left(V_w-V_o\right)}{\mathit{PV}}$$E9

where V_w is the volume of the produced water with oil flood, V_o is the volume of oil produced with waterflood and PV is the pore volume of the core.

Effective water permeability is calculated using Darcy’s equation and the end-point water relative permeability is calculated as the ratio of the effective water permeability (k_w) to the brine permeability (k_b) in the presence of S_or as per Eq. (10)

$$k_{\mathit{rw}}=\frac{k_w}{k_b}$$E10

Once no more oil is produced, up to 4 PV of the selected polymer at the target concentration are injected at the selected flow rate (chosen from the rates used to determine the brine permeability). The following data should be collected: pressure (total and differential), volume fractions, and viscosity of the produced fluids (oil and brines) as a function of time. After ending the polymer injection, brine is injected until the concentration of the polymer in the produced stream is very low (replicating the post-flush step done in the field).

At the end of the coreflood testing, it is recommended to do an additional polymer injection into a representative restored sample with the actual field saturation conditions (reproducing the saturation history of the field) to observe the behavior of the selected polymer candidates. This experiment can provide good insights on polymer performance and data for the simulation (including pseudo relative permeability curves), and it is typically not included in most laboratory screening and testing programs.

4. Final recommendations

Laboratory screening is an essential step in the design of polymer flooding. It is critical that the testing program is completed following validated workflows to avoid cost overruns and time delays.

We recommend using all information about the reservoir where the polymer injection will be done, collecting all required data on fluids, and doing the testing at reservoir conditions, for a better understanding of the formation response to the injection. In particular, polymer rheological properties tend to be affected by the chemical structure and other parameters.

Special attention should be given to the preparation and handling of all solutions. Vendor guidance on polymer preparation should be followed to avoid hydration issues upon mixing. All fluids should be properly characterized and stored to avoid degradation and/or contamination.

Among the recommending testing and sense check of the results here are some points to pay attention to—(a) evaluate the impact of polymer salinity on the solution viscosity, (b) analyze polymer rheology as a function of temperature to check for potential degradation [3, 11], (c) evaluate polymer solubility when using high salinity brine (due to strong interactions there could be changes in the polymer structure), (d) complete filtration ratio tests early in the experimental program, (e) check for biodegradation even if using synthetic polymers. If biocide is needed, make sure to select one that is compatible with the polymer, (f) check for the presence of any dissolved oxygen and reduced iron (Fe⁺²⁾ to prevent chemical degradation, (g) complete long term degradation tests even under time constraints to make sure the degree of hydrolysis does no change significantly with time and temperature [26, 28, 29], (h) if oxygen scavengers and/or biocides are used, make sure they do not compromise the polymer structure.

We recommend using rock samples representative of the formation lithology where the polymer will be injected, with attention to capture data on the impact of heterogeneity on polymer performance. The rock samples should be restored to the reservoir state as close as possible, and the fluids (oil, brine) to their reservoir conditions. Special attention is given to cases where clay is present [3].

Core flooding tests are recommended for use to understand polymer behavior and avoid discarding candidates based on the results of a single test. Analyze the experimental results holistically. Aim to understand the obtained values of RF and RRF. Look out for other effects that could result in certain trends like higher values of RF or RRF due to gel-type effects in aqueous solutions.

We proposed an integrated workflow with reference to the recommended testing and Quality Check steps for a successful laboratory polymer screening program. We also recommended adding an additional step of injecting the selected polymer candidate at reservoir conditions in a formation sample reproducing the saturation history of the reservoir where the EOR process will be deployed. This last step can provide valuable data and insights for the process upscaling and field simulation.