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Technology

Rethinking Risk: Why Enhanced Oil Recovery Still Lags and Why It Shouldn❜t

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 highpermeability 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.