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Technology

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

Conclusion. Beginning in No. 5 (November 2025)

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.

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.

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).

a. 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).

A summary table is shown below (Table 2):

Table 2 Flood characteristics for several pads in Milne Point.