Breaking the Mold: Reassessing Polymer Flooding and the Outdated ‘Primary, Secondary, Tertiary’ Model

I have written this paper “Breaking the Mold: Reassessing Polymer Flooding and the Outdated ‘Primary, Secondary, Tertiary’ Model” for the EAGE IOR+ 2025 in Edinburgh. You can access it on Earthdoc.

Introduction

We can start this introduction with a little game. Imagine that you’re an engineer-in-training, full of ambition and excitement about entering the oil and gas industry. Before even setting foot in school, you decide to get a head start and do some reading on how things work. Naturally, you begin with a quick internet search, typing in keywords like “oil recovery processes” or “oil extraction stages.”

As you scroll through the results, a clear structure begins to emerge across every article, presentation, and forum: Primary, Secondary, Tertiary. These stages are everywhere, presented as an orderly progression—first comes natural reservoir drive, then water or gas injection, and finally, Enhanced Oil Recovery (EOR) methods like polymer flooding, deployed only when the field is near the end of its economic life. This sequence is treated as an unchangeable formula, the industry’s traditional playbook for maximizing oil recovery.

However, you can’t help but wonder: if EOR techniques can boost recovery so significantly, why are they always left as a last resort? Why are all the other articles discussing how low the recovery factors are in general? 35% of oil recovered? 65% of oil left untapped? And it has been going on for the last 60 years? You begin to ask yourself—could introducing these advanced techniques earlier, before the reservoir has started to decline, change the game?

This paper explores precisely that question. By rethinking the “Primary, Secondary, Tertiary” sequence, we challenge an industry-wide convention and consider whether a more flexible, integrated approach to oil recovery could yield better results. Through a literature review and case studies, we’ll examine fields where operators introduced EOR techniques like polymer flooding earlier in development. The results suggest that breaking free from tradition and adopting a responsive, tailored approach might offer a way to enhance recovery efficiency, benefiting not just individual projects but the industry as a whole.

Language shapes perceptions and decisions

In oil and gas industry, engineers must navigate complex technical challenges, optimize production, and manage risks. However, one of the most impactful aspects of their work—decision-making—is often influenced by factors beyond technical expertise (Tversky & Kahneman, 1974; Bazerman & Moore, 2012). Understanding why decisions are made the way they are, how risks are evaluated, and why certain innovations are embraced or resisted requires more than engineering know-how; it calls for an open mind to insights from other fields, including social psychology.

Social psychology, with its focus on how people think, feel, and behave in social contexts, provides great tools for understanding decision-making processes. Concepts like cognitive biases, framing effects, and group dynamics are not just abstract theories—they have practical implications for industries where decisions carry enormous financial and environmental consequences (see for instance the explosion of Challenger in 1986; Vaughan (1996)).For engineers, integrating this knowledge into their toolkit is not just an academic exercise but a practical necessity, especially in a field like oil and gas, where the framing of risks and opportunities can dictate whether a project thrives or fails.

Behavioral scientists such as, for instance, Daniel Kahneman and Amos Tversky have demonstrated that the framing of information—the way choices are presented—can significantly influence decision-making. For instance, individuals are more likely to favor a sure gain over a probabilistic one, even if the expected value is the same. Conversely, when faced with potential losses, people often take greater risks to avoid them. This “loss aversion” bias means that people perceive losses as more significant than equivalent gains, leading to overly cautious or risk-averse behavior in some contexts and reckless risk-taking in others (Figure 1).

Figure 1 Illustration of the loss aversion bias (source: economicsonline.co.uk).

Framing is also closely tied to conservatism bias, where individuals favor existing practices or incremental changes over bold innovations. Terms like “Primary, Secondary, Tertiary Recovery” imply a linear, step-by-step progression, discouraging flexibility or deviation from established norms. This framing perpetuates a sense that certain methods, such as Enhanced Oil Recovery (EOR), should only be implemented as a “last resort,” even when earlier adoption might yield better results. Such linguistic framing reinforces the industry’s natural conservatism and slows the adoption of potentially transformative technologies.

Historical performances: 60+ years of primary, secondary, and tertiary recovery stages

“Every reservoir is different” is probably one of the most repeated statements in the industry, especially when it comes to trialing technologies proven in other contexts. However, instead of reiterating a statement that offers no practical solutions, it would be far more productive to focus on a universal characteristic shared by all oil-bearing formations: heterogeneity. Oil is left behind either because it is trapped or bypassed; these are the notions of macroscopic and microscopic sweep efficiencies. It implies that any fluid injected into a heterogeneous formation will inevitably follow the path of least resistance to the producer, leaving substantial oil volumes untouched, light or heavy (Figure 2). Of course, this issue can arise much faster with heavy crudes, but this doesn’t mean that high API oil reservoir will not suffer from early water breakthrough problems and low recovery factors.

Figure 2 Reservoir heterogeneity showing permeability variations (mD) across layers. Fluid flow behavior is represented by car icons: faster flow in high-permeability zones, restricted flow in low-permeability barriers.

As mentioned in the introduction, oil recovery stages are usually divided into 3 categories: primary, secondary and tertiary (Figure 3).

Figure 3 Oil recovery stages as described in most (if not all) books (from Lake et al. 2014).

Primary recovery uses the natural energy stored in the subsurface formation. Secondary recovery often involves the injection of a fluid for pressure support. One of the most popular secondary-recovery methods is waterflooding. Because primary recovery invariably results in pressure depletion, secondary recovery requires “repressuring”. Water injection emerged in the early 20^th century as a method to address the increasing production of saline water (brine) alongside declining oil output in wells. Initially, the brine was discarded into nearby streams, but by the 1920s, the practice of reinjecting it into subsurface formations began, notably in Pennsylvania’s Bradford oil field. Over time, water injection evolved into systematic methods like “line flood” and “five-spot” well layouts. It extended oil production by maintaining reservoir pressure and improving recovery rates, driven by the low cost and wide availability of water.

Very early, Muskat (1949) and Stiles (1950) recognized that variations in fluid mobility and permeability significantly affect waterflood performance, emphasizing that reservoirs with large permeability distributions lead to uneven fluid flow pathways. This issue, later discussed by Dykstra and Parsons, demonstrated that heterogeneity caused the injected water to preferentially flow through high-permeability “thief zones” while bypassing oil-rich, lower permeability regions. Aronofsky and Ramey (1956) further discussed the impact of mobility ratios on flood patterns and recovery dynamics, illustrating that such conditions lead to early water breakthrough and incomplete sweep efficiency. Dyes et al. (1954) also demonstrated that post-breakthrough oil recovery suffers when water channels through high-permeability zones, leaving significant volumes of oil stranded.

Since the 1920’s, many fields have been developed using the same staged approach and water injection.

What are the results?

For primary recovery (i.e., natural depletion of reservoir pressure), the lifecycle is generally short, and the recovery factor does not exceed 20% in most cases (it is much lower for heavy oils). For secondary recovery, the incremental recovery ranges from 15 to 25%. Globally, the overall recovery factors for combined primary and secondary recovery range between 35 and 45% (Zitha et al.). For the United Kingdom for instance, the expected recovery factor has consistently been around 42% to 43%. Currently, at the end of the basin’s life, it is expected that 57% of the oil originally in those developed fields will remain in the ground (OGA, 2018). For the NCS, recovery factor averages 47% (NPD, 2019).

As of 2021, the daily global production of brine from conventional oil and gas fields was estimated at approximately 300 million barrels with an increasing trend observed over time (Nabzar, 2011). The Water-to-Oil Ratio (WOR) had a global average of 3:1 to 4:1, meaning 3–4 barrels of water are produced for every barrel of oil. This value can vary significantly across oilfields in the world, ranging from 0.4:1 to 36:1. An increasing water-to-oil ratio not only poses challenges for managing the vast quantities of produced water but also highlights the escalating energy and environmental costs associated with mature oilfields.

Given the wealth of knowledge and information accumulated over the years, why so much attention on water flooding? This technique has historically been the preferred method for secondary oil recovery following primary production for several reasons, among which:

• Economic considerations: water injection typically offers a favorable Net Present Value (NPV) due to its relatively low operational and capital expenditures compared to more complex Enhanced Oil Recovery (EOR) techniques. This cost-effectiveness aligns with shareholder expectations for predictable and timely returns on investment. The paradox for engineers is that a favorable NPV doesn’t necessarily mean a high recovery factor (Farajzadeh et al., 2019, 2021).
• Cost and availability: Water is also generally abundant and inexpensive, making it a practical choice for injection processes. The widespread availability of water reduces logistical complexities and costs associated with sourcing and transporting injection fluids, further enhancing the economic appeal of water flooding.
• Conservatism: The oil industry has traditionally exhibited a conservative approach, often adhering to established practices. This risk-averse mentality favors the continuation of water flooding, a method with a proven track record, over the adoption of newer, less familiar EOR techniques that may carry higher perceived risks and costs (see introduction).
• “Need to know the reservoir”: Engineers often argue that water injection helps to better understand the reservoir. However, if this were true, recovery factors would be much higher after years of water flooding. Even after 20 years, around 65% of the oil typically remains unrecovered, revealing water flooding’s inability to address complex reservoir heterogeneities, such as poor sweep efficiency and unfavorable mobility ratios, and undermining the claim that it provides comprehensive reservoir insights. Water injection can provide valuable reservoir insights within a much shorter timeframe than the typical 20-year span often associated with waterflooding. Some key information includes identifying reservoir boundaries, compatibility with the reservoir rock, estimating parting pressure, assessing fundamental reservoir properties such as permeability, and evaluating some inter-well connectivity. Waiting too long will lead to early breakthrough and poor sweep efficiency.

Myopic Approach to NPV & Energy

Parra Sanchez (2010) has shown that adopting a life cycle perspective is essential for maximizing the total Net Present Value (NPV) over the entire duration of a project, rather than focusing on maximizing short-term returns in individual recovery phases. This approach requires a comprehensive assessment of how decisions made during earlier stages—such as primary or secondary recovery—impact the efficiency and profitability of subsequent phases, particularly when implementing Enhanced Oil Recovery (EOR) methods like polymer or CO₂ flooding. Optimizing the timing of transitions between recovery phases is crucial and utilizing life cycle optimization models can help determine the optimal points for introducing new techniques. Another metric used in the industry is the Unit Technical Cost (UTC). While it is useful for assessing short-term cost efficiency, it falls short in addressing the broader, long-term dynamics of field development. Some limitations can include its focus on minimizing immediate costs, a lack of integration with profitability metrics like Net Present Value (NPV), and the inability to guide optimal timing for recovery transitions. By contrast, NPV evaluates profitability over a project’s lifecycle, making it essential for long-term strategies. Combining UTC with NPV in lifecycle optimization models makes sense to:

• Balance short-term costs and long-term gains, such as higher recovery from early EOR implementation.
• Optimize transition timing to avoid inefficiencies like poor sweep and bypassed oil zones.
• Incorporate sustainability and operational costs, which are often overlooked in UTC calculations.

The two following graphs illustrate the critical difference between myopic optimization of Net Present Value (NPV) for individual recovery phases and global NPV optimization across the entire lifecycle of a project. In the first graph (Figure 4), the approach focuses on maximizing NPV at each recovery phase independently. While this method achieves a cumulative discounted cash flow of $971 million and recovers approximately 58% of the Original Oil In Place (OOIP), the recovery process spans 87.5 years, a suboptimal outcome in both economic and operational efficiency.

Figure 4 Myopic NPV optimization with approach per stage (971 million dollars) (from Parra Sanchez, 2010)

The second graph (Figure 5) shows a life-cycle approach to optimize NPV across the entire project duration. This approach significantly reduces the time required to recover oil, achieving nearly 50% recovery of OOIP in just 25.9 years while doubling the cumulative discounted cash flow to $1.9 billion. The sharper recovery curves and earlier attainment of peak NPV highlight the benefits of a globally optimized strategy, which aligns recovery methods and transitions to maximize overall efficiency, rather than focusing on incremental gains at each phase.

Figure 5 NPV optimized over the lifecycle of the field (1.9 billion dollars) (from Parra Sanchez, 2010).

Resource allocation should be guided by assessing recovery efficiency across all recovery phases, investing in technologies and strategies that enhance the ultimate recovery factor rather than focusing solely on incremental gains within individual stages. Non-engineering factors—including economic, regulatory, and market conditions—should also be incorporated into the optimization process, as elements like fluctuating oil prices or carbon credit incentives can influence the viability of certain EOR methods. Importantly, implementing a feedback loop to continuously monitor reservoir performance and adjust strategies as necessary ensures that life cycle optimization remains a dynamic process, evolving with new data and operational insights.

It should also be remembered that, as each recovery phase progresses, the remaining oil saturation in the reservoir decreases, making subsequent recovery increasingly challenging and more expensive (especially UTC). By the time tertiary recovery, is initiated, the oil saturation is lower, and the remaining oil is often trapped in small pore spaces or isolated regions, requiring more sophisticated and costly techniques to mobilize it (while reservoir characterization has not improved much…). These methods involve higher capital and operating costs, for a lower prize (Figure 6).

Figure 6 More expenses for a lower prize: the paradox of the staged-oil recovery approach.

Farajzadeh et al. (2019, 2021) demonstrated in a study that using an exergy-based analysis provides valuable information about the energy efficiency and CO₂ intensity of oil recovery processes, particularly in mature water injection projects. Exergy, defined as the useful work obtainable from a system based on its thermodynamic state, serves as a comprehensive measure to evaluate the energy invested in producing oil. The authors show that as the water cut (fw) in water injection projects approaches 90%, the exergy required to manage the excessive volumes of produced water becomes disproportionately high (Figure 7). This results in indirect CO₂ emissions from energy consumption during water handling and reinjection that rivals the emissions from burning the produced oil. By applying exergy-return on exergy-investment (ERoEI) analysis, the study quantifies these inefficiencies and advocates for transitioning to polymer flooding, a method that reduces water cut by enhancing the mobility ratio of the displacing phase. This leads to more efficient oil recovery, significantly lowers exergy consumption, and reduces the associated CO₂ emissions.

Figure 7 Relationship between water cut (fw​) and energy consumption (exergy) and CO₂ emissions per barrel of oil produced. The left y-axis represents unit exergy invested (kWh/bbl oil), while the right y-axis shows unit CO₂ emitted (kg CO₂/bbl oil). As water cut increases, both energy consumption and CO₂ emissions rise exponentially, illustrating the inefficiencies and environmental impact of managing high water production in mature reservoirs (from Farajzadeh, 2021).

Another way to look at the graph is to work to delay fluid (water) breakthrough knowing that this will occur at some point because of heterogeneities. This requires a pro-active approach to limit later expenses.

This leads us to draw a summary of 60+ years of secondary recovery, primarily through waterflooding:

• The oil recovery factor remains below 40% on average.
• Water production significantly outweighs oil, with a current ratio averaging 4 barrels of water for every barrel of oil, often increasing above 5:1.
• CO₂ emissions rise exponentially as the water cut exceeds 90%.

Given all these outcomes and publications, it seems imperative for engineers and managers to take a pause and consider: is there a more effective approach to enhance oil recovery while minimizing all forms of waste (exergy, energy, CO₂, water, time, money)?

Why EOR and why early

Discussions on EOR deployment tend to follow industry cycles, with recurring publications questioning whether the time has finally come (e.g., Al-Mjeni et al., 2010; Delamaide, 2021).In 2018, the IEA released a report titled: IEA (2018), “Whatever happened to enhanced oil recovery?” in which the authors described the purpose of their work: “Despite this range of projects, today EOR represents only around 2% of global oil supply and it remained in the background even during previous periods of high oil prices (such as between 2010 and 2014). If EOR did not take off during these periods, does this mean it will never do so? Or could EOR projects make a comeback? More broadly, could the use of CO₂ for EOR even make this technology part of a global response to climate change?”.

The authors’ initial compilation of chemical Enhanced Oil Recovery (EOR) projects was unfortunately incomplete, omitting over a dozen significant projects including: Grimbeek (Juri et al., 2017), Captain (Poulsen et al., 2018), Patos-Marinza (Hernandez et al., 2016), Kazakhstan (Abirov et al., 2015), Matzen (Sieberer et al., 2017), Belayim (Lazzarotti et al., 2017), and Tambaredjo (Delamaide et al., 2017) to name a few.

At that time, the reasons put forward by the IEA behind limited EOR deployments were:

• “The incentive to pursue EOR is often highest when and where there are concerns over resource scarcity. There are fewer such concerns today.
• There is a current preference in the upstream industry for projects that can generate fast returns. An EOR project requires time to plan, test and implement, and generates incremental production only in the latter stages of a field’s lifetime.
• EOR has become a niche business among oil and service companies, and the requisite skills, technologies and expertise are not widely available. Five midsize oil and gas companies currently operate the majority of CO₂-EOR projects in the United States.
• Costs for EOR have come down since 2014, but the costs of other projects – including shale and offshore developments – have come down more quickly. For the moment at least, EOR technologies struggle to compete with other investment opportunities.”

While we do not want to exhaustively review all the arguments, it is worth highlighting the reasoning behind the cost-related aspects, as they are central to the focus of this paper. Statements like, “In the upstream industry, priority is often given to projects that deliver rapid returns. An EOR project, however, requires significant time for planning, testing, and implementation, with incremental production realized primarily in the later stages of a field’s life cycle,” reflect a myopic emphasis on short-term NPV optimization. It assumes that EOR should come later in the field’s life and disregards the lessons learned over six decades of waterflooding and recent (and less recent) polymer flooding projects. Moreover, exploring and drilling for new resources are inherently high-risk and capital-intensive activities, with the rate of significant new discoveries declining sharply over the past decade (Figure 8).

Figure 8 Global discoveries falling to a lowest in decades (source: Rystad)

From a technical perspective, early initiation of EOR, such as polymer flooding, aligns with the fundamental principles of fractional flow theory, which indicates that injecting viscous fluids enhances mobility control, delays water breakthrough, and improves sweep efficiency by mitigating viscous fingering (Figure 9). Moreover, implementing EOR early ensures that the reservoir’s pressure and saturation conditions are more favorable, leading to a higher displacement efficiency and better recovery. Delaying EOR can also lead to technical challenges such as early polymer breakthrough, and reduced injectivity in high-water-cut reservoirs, which complicate project economics and recovery efficiency.

Figure 9 Fractional flow comparison of polymer flooding performance in different scenarios. The graphs depict % of mobile oil recovered versus pore volumes (PV) injected. The curves represent results for 1 Layer (red), 2 Layers with Crossflow (green), 2 Layers with No Crossflow (purple), Piston-like Displacement (black, theoretical optimum). The left graph shows polymer flooding performance initiated after primary recovery (secondary polymer flooding), while the right graph illustrates polymer flooding in a tertiary recovery stage after 5PV of water injection. Earlier polymer injection improves oil recovery efficiency, achieving higher recovery at lower pore volumes injected, particularly in layered reservoirs with crossflow (Source: Seright PPRC website).

From an economic standpoint, starting EOR earlier helps to reduce cumulative water production and handling costs, which escalate as water cuts increase in mature fields. The exergy concept discussed by Farajzadeh, which evaluates the energy efficiency of oil recovery processes, shows that the energy required for extraction increases with time as water-handling demands grow, decreasing the overall thermodynamic efficiency of the process.

In the next paragraphs, we will make the case for polymer flooding and illustrate the above statements with field cases.

A case for polymer flooding

Polymer flooding is a technology with a proven track record which enhances oil recovery by improving sweep efficiency and the mobility ratio between the injected water and reservoir oil (See Seright & Wang, 2021, for a status review). By rendering the displacement front more homogeneous, it also helps delay and reduce water production, leading to lower handling and disposal costs, which is particularly valuable in mature fields with high water cuts. Economically, polymer flooding provides a cost-effective solution with significant incremental oil recovery, often ranging between 10% and 20% of the original oil in place (OOIP) (Thomas, 2019).

A great illustration of the benefits of the technology can be found in the publications describing the Captain offshore polymer injection. The reservoir is the Southern Upper Captain Sandstone (SUCS) with exceptional reservoir properties, including 96% Net-to-Gross, 31% porosity, 5 Darcy permeability, a low-API gravity oil, and an unfavorable end-point mobility ratio of 31. In 2018, Poulsen et al. shared the key numbers for the project, with similar positive results shared later by Johnson et al. (2023):

• Incremental Oil Recovery: 1.4 MMSTB (additional recovery from polymer flood beyond waterflood EUR).
• Total production from polymer flooding: 2.5 MMSTB.
• Water handling reduction offshore: 25.2 MMSTB less water produced under polymer flooding compared to waterflood.
• Chemical Efficiency: 2.7 lbs/bbl of incremental oil produced.
• Time Acceleration to EUR: 6 years earlier recovery compared to waterflood.

Figure 10 illustrates the above points.

Figure 10 Results from the polymer injection pilot in Captain showing production acceleration and incremental oil over waterflooding (Poulsen et al., 2018).  

Skauge et al. (2024) published for this field a synthesis of the benefits including the reduction in energy consumption and CO₂ emissions:

• Incremental Recovery & Acceleration: polymer flooding reduced the operational duration by 33 years for Area B and 63 years for Area C compared to water flooding, for the same cumulative oil recovery.
• Water Cut Reduction: in Area B, the water cut fell from an initial 94.1% to 80% during polymer injection, with no return to initial levels until 7 years post-injection.
• CO₂ Emissions Reduction: polymer flooding resulted in a 35% reduction in CO₂ emissions compared to water flooding.
• Energy Efficiency: ehe Exergy Return on Exergy Investment (ERoEI) was 2.4 times higher for polymer flooding versus water flooding.
• Polymer injection incurs a significant exergy cost due to the energy-intensive process of polymer production, which is 2.5 times higher than the total exergy required for water flooding. However, the energy efficiency of polymer flooding makes it a more favorable option. Over a six-year period of polymer injection followed by five years of water flooding, the same oil recovery is achieved as with 75 years of water flooding alone. Despite the higher initial exergy investment for polymer flooding, the substantial increase in oil recovery—enabled by improved sweep efficiency—more than compensates for the additional energy expenditure.

Public data from other projects and countries reveal the potential to improve oil recovery by polymer injection. The most striking example comes from Argentina with a dramatic increase in oil production followed by large-scale deployment of polymer flooding (including Grimbeek and Diadema), Figure 11.

Figure 11 Oil production by block in Argentina from January 2009 to October 2024. See Manantiales Behr in yellow (Grimbeek area with massive polymer injection). (Source: Energy Secretariat of the Argentine Republic).

Another example of success story is Mangala polymer project (Cairn India) with full-filed polymer flood started in 2015 and 165 tons/day polymer consumption through ~500 000 bwpd of polymerized water injection. Polymer flood reversed the production decline and is expected to give ~8% incremental recovery of STOIIP (~100 MMbbls) by 2030 (Prasad et al., 2022). These results for this project show clearly the benefits of polymer injection to enhance oil recovery while limiting energy wastes and indirect CO₂ emissions. The only uncertainty remaining is about the right timing to start polymer injection as this example covers tertiary implementation

A field example comparing secondary vs. tertiary polymer flooding

The Milne Point field study (Hilcorp) offers a compelling comparison of secondary and tertiary polymer flooding strategies, focusing on critical performance metrics such as recovery factor, injectivity, water breakthrough timing, and overall efficiency (Aitkulov et al., 2024). The project started in 2018 with 6,000 bwpd and has expanded to 57,000+ bwpd with over 50 injection wells and 9 polymer skids currently active in 2024. The main reservoir characteristics are presented in Table 1.

Table 1 Milne Point main reservoir characteristics (Aitkulov et al., 2024).

Aspect	Details
Reservoir Depth (ft)	3600-4000
Temperature (°F)	70-90
Oil Viscosity (cP)	10-1300
Water Salinity (ppm)	25000
Injection Water Salinity (ppm)	3000

Recovery factor

Secondary polymer flooding, such as the L Pad Nb pattern, achieved superior recovery factors compared to tertiary flooding. The L Pad recovered 34% of the original oil in place (OOIP) after polymer injection, doubling the recovery predicted by waterflooding fractional flow analysis, which estimated 17% at 1 pore volume injected (PVI). By contrast, tertiary flooding in the J Pad Nb pattern recovered 28% of OOIP after 40% PVI. While the J Pad demonstrated substantial incremental recovery compared to waterflooding, it fell short of the efficiency seen in secondary flooding. This confirms that initiating polymer flooding early, before water saturation increases significantly, is more effective in maximizing recovery (Figure 12).

Figure 12 Comparison of recovery factors for the initial injection patterns of L Pad Nb (left) and J Pad Nb (right) as a function of pore volume injected. Simulation results for different mobilities (M=1, 2, 3) are shown as green, orange, and dotted blue curves, respectively, while the observed data (red curves) represent the actual recoveries. Black triangles indicate the start of polymer flooding (PF Start). Forecast/Results for waterflooding alone (WF) are also included (dotted blue curves) (Aitkulov et al., 2024).

A summary table is shown below (Table 2):

Table 2 Flood characteristics for several pads in Milne Point.

Pad	Flood Type	Oil Viscosity (cP)	Spacing (ft)	Well Length (ft)	Recovery Factor (%)	Water Cut Reduction	Injectivity Changes
J Pad (Nb)	Tertiary	350	1100	4500	28	Max 50%	Increasing with maturity
L Pad (Nb)	Secondary	850	800	7000	34	No appreciable until 21% PVI	Flat or increased
M Pad (Oa)	Secondary	85	400	10000	Too immature	N/A	Constant at 400ft spacing
I Pad (Nb)	Tertiary	175	1100	8250	10	From 75% to 50%	50% decrease
S Pad (Nb)	Tertiary	45	1400	8400	10	From 50% to 75%	Variable 50%-0%

Injectivity and throughput

Injectivity remained more stable in secondary polymer flooding compared to tertiary flooding. In the L Pad, injectivity exhibited minimal degradation throughout the polymer flood, with consistent injection rates and sustained oil production. In contrast, the J Pad experienced a 60% decrease in injectivity shortly after polymer injection began, largely due to the transition from waterflooding to the more viscous polymer solution. However, as the flood matured, injectivity in J Pad gradually improved, stabilizing at levels that allowed for continued production. Despite this recovery, the initial reduction slowed throughput rates, highlighting the operational complexities of tertiary floods, particularly when introducing polymers into reservoirs with significant water injection histories (Figure 13).

Figure 13 Well injectivities for L Pad Nb (left) and J Pad Nb (right) as a function of pore volume injected. The bottomhole injectivity (bwpd/psi/1000ft) is plotted for individual wells, with polymer flooding (PF) start points marked as triangles. In L Pad Nb, wells L-51, L-52, L-53, L-59, and L-61 are shown, while in J Pad Nb, wells J-23A, J-24A, and J-30 are displayed. Observed trends illustrate the variations in injectivity before and after polymer flooding initiation in secondary (left) and tertiary (right) modes (Aitkulov et al., 2024).

Water breakthrough timing and management

The timing of water breakthrough differed significantly between secondary and tertiary floods. In the L Pad, which began directly with polymer injection, water cuts remained below 10% for most of the operation, delaying water breakthrough and reducing the need for extensive water management. In the J Pad, water breakthrough occurred earlier due to the reservoir’s prior waterflood history. While polymer injection temporarily reduced water cuts, they eventually returned to levels comparable to those seen during the waterflood.

Overall efficiency and time to recovery

Secondary flooding demonstrated greater overall efficiency, recovering more oil with lower water production and less PVI. For instance, the L Pad achieved a recovery factor of 34% OOIP with minimal water cuts and fewer operational challenges. Tertiary flooding, while effective, required higher PVI to achieve incremental recovery, and the increased water cuts further reduced its operational efficiency. Additionally, secondary polymer flooding achieved its recovery targets in a shorter time frame, accelerating production and improving project economics.

Comparative insights and conclusions

Aspect	Secondary Flood	Tertiary Flood
Recovery factor (RF)	Up to 34% (L Pad)	Up to 28% (J Pad)
Water Cut	Low (<10% for up to 21% PVI)	Reduced from high initial values (e.g., 65%-75% down to ~50%)
Injectivity performance	Stable or increased (L Pad)	Decreased by up to 60% (e.g., J Pad)
Pore volume injected (PVI)	Better recovery at lower PVI (e.g., exceeded waterflood RF at 1 PVI with 0.1 PVI polymer)	Moderate efficiency, higher PVI requirements
Injected mobility ratio	0.7–1.9 (optimal)	0.8–2.0 (moderate efficiency)
Oil viscosity range (cP)	85–850 (e.g., L Pad 850 cP)	350–450 (e.g., J Pad 350 cP)
Well spacing	400–800 ft (tighter spacing improves efficiency)	800–1100 ft (wider spacing reduces efficiency)
Throughput efficiency	3x higher throughput in tighter spacing (e.g., M Pad Oa North)	Lower throughput due to spacing and injectivity losses
Key challenges	Reservoir heterogeneity; injector-to-producer communication limits	Higher water cuts; injectivity declines due to mixing issues
Notable observations	Early application avoids hysteresis; maintains low water cut	Demonstrated recovery potential even after waterflood inefficiencies

Table 3 Summary of notable observations comparing secondary and tertiary polymer floods in Milne Point

Other evidence in favor of secondary polymer flooding can be found in Delamaide (2021) for Pelican Lake.

Conclusions: breaking the mold

The oil recovery industry is at a turning point, with fewer large discoveries, a shortage of skilled workers (Brannstrom et al., 2022), and a need to rethink long-standing practices and language based on years of data and new advancements. Over 60 years of waterflooding have yielded suboptimal results, with global recovery factors averaging below 40%, significant water-to-oil ratios exceeding 4:1, and CO₂ emissions escalating as water-cuts reach 90%. Old and new literature on reservoir development, fractional flow theory, exergy analysis, Net Present Value (NPV) optimization, and recent field cases clearly supports the case for reconsidering the timing for implementing the so-called Enhanced Oil Recovery (EOR) techniques earlier in the lifecycle. Case studies such as Hilcorp’s Milne Point or CNRL’s Pelican Lake projects demonstrate that early polymer flooding achieves higher recovery factors, reduces water cut, and maintains stable injectivity, whereas tertiary flooding struggles with injectivity challenges and inefficiencies inherited from prior waterflooding. These findings align well with reservoir engineering principles, emphasizing that the natural heterogeneity of reservoirs causes injected fluids to follow the path of least resistance. This leads to bypassed oil and inefficiencies if conformance is not managed early. Secondary EOR is expected to consistently deliver better results than tertiary approaches, as heterogeneity is a common characteristic of all reservoirs.

Time to rethink

It is time to rethink the outdated language and biases that have held back progress in oil recovery. In 2024, the SPE community asked for public feedback on suggested changes to IOR/EOR terminology (JPT, 2024). Surveys revealed that many people struggled to understand these terms, highlighting the need for clearer language. However, the new proposals, including adding a new term (AOR), left some people even more confused. While starting the discussion was a great step forward, it probably made things even more complicated.

More importantly, the traditional “Primary, Secondary, and Tertiary Recovery” model forces a rigid, step-by-step approach that delays the use of new technologies and kills creative thinking. This framework encourages risk avoidance and slows innovation. A better way is to start fresh, organizing recovery methods by what they do rather than when they’re used. For example, Baseline Recovery (BR) covers natural oil recovery without extra help, while Assisted Oil Recovery (AOR) focuses on methods that boost efficiency. Subcategories like Surface-Controlled Recovery (SCR) handle changes at the surface (wells, facilities, etc.), and Subsurface Injection Recovery (SIR) focuses on injecting fluids into the reservoir. These can be broken down further into Native Fluid Injection (NFI) (e.g., water or gas reinjection) and Non-Native Fluid Injection (NNFI) (e.g., polymer flooding or CO₂ injection).

To break the mold, the industry needs a fresh start with simpler language and new strategies. This means questioning old habits, investing in training, and focusing on models that improve recovery and sustainability throughout a reservoir’s life. Rational arguments against early EOR adoption, even those based on NPV optimization, are eroding. What remains are irrational barriers—cognitive biases, industry conservatism, and misplaced risk aversion—that delay progress and perpetuate inefficiencies.

References

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