Injectivity in Polymer Flooding – What You Need to Know
Predicting Injectivity in Polymer Flooding is a topic that comes up constantly. Over the years, I’ve been asked the same questions again and again:
– How much injectivity will we lose?
– How quickly can it change?
– Will the polymer even inject properly?
These are all important concerns, but sometimes they are overstated. I remember when engineers were worried that exceeding 3cP viscosity would cause fractures, just because a simulation suggested it. This made me realize how much uncertainty exists around injectivity predictions. A few years ago, I co-authored a paper with SLB to explore why polymer injectivity is so hard to predict. Since then, I’ve wanted to revisit the topic and go deeper into the details. This page contains a lot of information on injectivity.
You can also check our YouTube channel for additional videos and podcasts and navigate the Polymer Flooding Guide for more content or our Academy for training courses where this topic is exhaustively discussed.
Table of Contents
Podcast - A discussion on Injectivity with Randy Seright
In this video, we discussed polymer injectivity during polymer flooding with Randy Seright.
A Summary on Injectivity
In this discussion, I start by defining injectivity and the different factors that influence it. I break down key mechanisms such as polymer rheology, shear-thinning, shear-thickening, drag reduction, and reservoir behavior.
I also look at real-world examples where injectivity didn’t behave as expected. Some projects saw less injectivity loss than predicted, while others experienced unexpected changes due to fractures, polymer degradation, or reservoir properties. By studying these cases, we can learn what really happens in the field and improve our predictions. This sections is followed by additional publications on the topic.
Why This Matters
Many models and simulations struggle to capture the real complexity of injectivity. Understanding these limitations helps us make better decisions in the field and avoid overcomplicating things with unnecessary assumptions.
If you work with polymer flooding or are just interested in how injectivity works, you will find in this page practical insights into the challenges and solutions.
You can also check our YouTube channel for additional videos and podcasts and navigate the Polymer Flooding Guide for more content or our Academy for training courses where this topic is exhaustively discussed.
Publications on Injectivity
We provide a list of publications on injectivity during polymer flooding.
Polymer injection to improve and/or accelerate oil recovery is a widespread technique with numerous ongoing and successful projects. In recent years, many field cases have been reported with injected polymer viscosity ranging from 5 to 160cP, producing large incremental oil volumes, without major injectivity issues. These field results often contradict pessimistic predictions of injectivity from prior studies. Despite abundant publications on the subject, there is no standard explanation of the reasons for discrepancies between forecast and actual behavior, and many questions are not yet fully answered. Will it be possible to inject the polymer solution at target viscosity? How much to inject? How fast? Will high pressures lead to fracturing or polymer degradation? Should the polymer solution be pre-treated, pre-sheared? What should be done if planned injection rates are not achievable? Will injectivity decline over time? These questions are very topical when it comes to building a business case for EOR, using 3D reservoir simulation models for forecasting production and calculating the economics of the project.
In this paper, we present a critical review of selected field cases from the literature, analyzing reservoir characteristics and development history as well as properties of the injected solution. We discuss the mechanisms which can affect injectivity, including polymer solution rheology, near-well flow regimes, reservoir heterogeneity and geomechanical effects, and how these mechanisms can be represented in reservoir simulation models. Based on this investigation, we propose appropriate methodologies for dynamic modeling of polymer injection, considering the impact on predicted flow behavior of assumptions about polymer physics, selection of key parameters for sensitivity studies and the issues of upscaling from core experiments to the field. We suggest guidelines for using laboratory measurements and field observations, and for implementing forecasting workflows. Finally, we make recommendations on designing a practical field injection and monitoring program, to obtain data for calibrating models and improving future predictions.
During polymer flooding for enhanced oil recovery (EOR), an essential design concern is whether the polymer solution acts as a pressure barrier that impedes displacement efficiency. This work evaluates scenarios where polymer bank forms a pressure barrier, using analytical and numerical modeling. The results show that in a single-layer system or where crossflow is not significant, the maximum polymer viscosity should not exceed the oil bank mobility to avoid excessive pressure drop. In multi-layer systems with crossflow, a trade-off exists between injectivity and mobility control. In these cases, moderate fractures around the injector may improve injectivity without significantly impacting sweep efficiency. The study emphasizes the importance of timing for polymer injection and supports earlier implementation to improve performance. Field examples from Daqing, Tambaredjo, and Pelican Lake are used to illustrate these principles
For applications in which enhanced-oil-recovery (EOR) polymer solutions are injected, we estimate injectivity losses (relative to water injectivity) if fractures are not open. We also consider the degree of fracture extension that may occur if fractures are open. Three principal EOR polymer properties are examined that affect injectivity: (1) debris in the polymer, (2) polymer rheology in porous media, and (3) polymer mechanical degradation. An improved test was developed to measure the tendency of EOR polymers to plug porous media. The new test demonstrated that plugging tendencies varied considerably among both partially hydrolyzed polyacrylamide (HPAM) and xanthan polymers.
Rheology and mechanical degradation in porous media were quantified for a xanthan and an HPAM polymer. Consistent with previous work, we confirmed that xanthan solutions show pseudoplastic behavior in porous rock that closely parallels that in a viscometer. Xanthan was remarkably resistant to mechanical degradation, with a 0.1% xanthan solution (in seawater) experiencing only a 19% viscosity loss after flow through 102-md Berea sandstone at a pressure gradient of 24,600 psi/ft.
For 0.1% HPAM in both 0.3% NaCl brine and seawater in 573-md Berea sandstone, Newtonian behavior was observed at low to moderate fluid fluxes, while pseudodilatant behavior was seen at moderate to high fluxes. No evidence of pseudoplastic behavior was seen in the porous rock, even though one solution exhibited a power-law index of 0.64 in a viscometer. For this HPAM in both brines, the onset of mechanical degradation occurred at a flux of 14 ft/d in 573-md Berea.
Considering the polymer solutions investigated, satisfactory injection of more than 0.1 pore volume (PV) in field applications could only be expected for the cleanest polymers (i.e., that do not plug before 1,000 cm³/cm² throughput), without inducing fractures (or formation parts for unconsolidated sands). Even in the absence of face plugging, the viscous nature of the solutions investigated implies that total injectivity must be less than one-fifth that of water if formation parting is to be avoided (unless the injectant reduces the residual oil saturation and substantially increases the relative permeability to water). Since injectivity reductions of this magnitude are often economically unacceptable, fractures or fracture-like features are expected to open and extend significantly during the course of most polymer floods. Thus, an understanding of the orientation and growth of fractures may be crucial for EOR projects in which polymer solutions are injected.
Two new methods were developed for anaerobically sampling polymer solutions from production wells in the Sarah Maria polymer-flood-pilot project in Suriname. Whereas previous methods indicated severe polymer degradation, the improved methods revealed that the polymer propagated intact more than 300 ft through the Tambaredjo formation. Our results may help explain the inconsistency between good production responses and highly degraded polymer observed in many past field projects. Analysis of produced salinity, polymer concentration, and viscosity indicated that the polymer banks retained low salinity and, therefore, high viscosity for much of the way through the Sarah Maria polymer-flood-pilot pattern. A strong shear-thickening rheology was observed for 1,000 ppm and 1,350 ppm hydrolyzed polyacrylamide (HPAM) solutions in porous media, even though the salinity was only 500 ppm total dissolved solids (TDS). Examination of injectivities revealed that these solutions were injected above the formation parting pressure in the Sarah Maria polymer-injection wells. Injectivity was insufficient until fractures were initiated hydraulically; however, the fractures propagated a distance of only approximately 20 ft and did not jeopardize sweep efficiency. In contrast, the short fractures greatly improved polymer injectivity and reduced concern about polymer mechanical degradation
This paper provides a comprehensive analysis of polymer injectivity in the Burgan field, the world’s largest sandstone oil field, particularly the Wara reservoir. Polymer flooding in the Wara formation is a strategic objective for the field plan to reach the Kuwait oil production target. The study provides corefloods, rheological polymer measurements, fracture pressure field measurements, and long-term polymer field injectivity tests. All the data have been critically evaluated using analytical models to assess the polymer injectivity and potential fracture initiation and extension.
Laboratory measurements of polymer bulk and in-situ viscosity were conducted using viscometers, while corefloods assessed HPAM polymer viscoelasticity under reservoir conditions (55°C, 162,000 ppm TDS). Step-rate tests in the field determined fracture initiation pressures, and long-term injectivity tests were performed in three wells at multiple rates. Field pressure responses were analyzed alongside coreflood results using the Unified Viscoelastic Injectivity Model (UVIM) coupled with a PKN fracture model. Fluids flow-back analysis assessed polymer degradation, and geomechanical studies provided insights into fracture direction. This integrated approach ensured a thorough understanding of fracture initiation and polymer behavior.
Initial predictions suggested that no fractures would occur during polymer injection. However, detailed analyses revealed that fractures were indeed occurring. This conclusion was drawn by comparing polymer injectivity at various polymer concentrations with water injectivity. Polymer injectivity was found independent of polymer concentration—indicating potential in-situ fracture formation due to polymer viscoelasticity. Laboratory coreflood experiments confirmed these findings, demonstrating that when the injection velocity exceeds 40 ft/day, the polymer’s extensional viscosity increases due to viscoelastic effects. As a result, the calculated pressure surpasses the fracture pressure of 2500 psi (as measured in step-rate tests). The UVIM fracture model estimated a fracture extension of approximately 80 ft from the well. These findings are crucial for the effective planning of field-scale polymer flooding. The analysis indicates a need to clearly define the objective and design of polymer flooding within a high permeability contrast reservoir.
This study provides critical insights into polymer injectivity and fracture management in the world’s largest sandstone oil field. It offers a novel, data-driven workflow for optimizing polymer flooding, addressing fracture risks from lab to field scale. The findings are vital for enhancing polymer flooding efficiency and improving field-scale implementation, contributing significantly to the petroleum industry’s understanding of polymer-induced fracture behavior