Opinion: The Oil & Gas Industry Is Finally Catching Up to What Chemistry Can Deliver

by Martin Shumway

For more than a decade, the shale industry has squeezed impressive gains out of mechanical optimization. Horizontal laterals that once averaged about a mile now commonly extend 2–3 miles, with many wells in major US plays exceeding 10,000–12,000 feet. Operators have packed more stages and clusters into every lateral and doubled or tripled proppant and fluid intensity per foot compared with early-shale development. Those changes drove remarkable capital efficiency,  more barrels per rig, more reservoir contact per dollar,  and underpinned the rise of US tight oil and gas.

They’re also running into natural limits.

Even with “factory” drilling and highly engineered frac designs, most unconventional wells still recover only a small fraction of the hydrocarbons in place. Across liquids-rich shale plays, published recovery factors are generally in the single digits, often 3–10% of original oil in place, compared with 30–60% recovery in many conventional reservoirs. In other words, we have built a highly efficient system for draining the easiest few percent of these reservoirs and leaving the rest behind.

The next wave of performance gains will not come from drilling even faster or pumping even harder. Mechanically, we have already lengthened laterals, pushed stage density, and increased proppant loading to the point where incremental gains are smaller and, in some basins, productivity per foot is flattening. Simply adding more sand and water does not change the physics of how trapped hydrocarbons move through tight rock.

The physics are clear. Unconventional reservoirs are dominated by nanopores, pore throats often tens of nanometers across or smaller, with permeabilities measured in microdarcies or below. At that scale, flow is controlled less by “permeability” in the traditional sense and more by capillary forces, rock–fluid wettability, and adsorption. Capillary pressure depends on interfacial tension, contact angle, and pore-throat radius (the Young–Laplace relationship), meaning oil can remain effectively locked in place even when a fracture network passes nearby. Mechanical design determines where the fractures go; chemistry determines whether the fluids can actually move.

That is why the next phase of unconventional performance is about increasing recovery factor, and that requires better chemistry.

From Mechanical Arms Race to Recovery Factor

We’re now seeing this shift move into the industry’s mainstream narrative. A recent Bloomberg column on “shale 4.0” framed recovery-factor improvement as the next major prize, quoting Chevron’s CEO on the need to go after the 80–90% of oil current practices leave in the ground. At the same time, the majors have discussed early-stage enhanced oil recovery pilots in shale, including surfactant- and gas-based treatments and huff-’n-puff schemes designed to bring more hydrocarbons out of the same rock.

When an operator of that scale starts talking about chemistry as a lever for long-term shale performance, it confirms a shift that has been building quietly for years. Chemistry is becoming a strategic driver,  not a supporting detail.

At the same time, majors are openly discussing early-stage enhanced oil recovery concepts in shale including surfactant-based treatments, gas-assisted cycles, and related schemes aimed at drawing more hydrocarbons out of the same rock. When operators of that scale start talking about recovery factor and surfactants as levers for long-term shale performance, it confirms a shift that has been building quietly for years: chemistry is moving from a supporting role to a strategic driver.

For many of us, it’s also strong validation. It reflects what we’ve been working toward in the field: the right chemistry can move the production needle in ways mechanical optimization alone cannot.

Why Surfactants Matter

Advanced surfactant systems, including biosurfactant-based technologies, are specifically designed for the realities of unconventional reservoirs. Lab and field work over the past decade has shown that well-formulated surfactant packages can:

• Reduce oil–water interfacial tension, helping mobilize residual oil and improve cleanup of completion fluids.
• Alter rock wettability, moving systems from more oil-wet toward more water-wet, which enhances imbibition and mobilization of trapped hydrocarbons.
• Form nano-scale microemulsions that can navigate tight pore networks and desaturate trapped fluids.
• Maintain performance under harsh conditions, remaining stable in high-salinity, high-temperature brines typical of many shale plays.

These are not theoretical benefits; they are showing up in actual wells and have been for some time (Locus BioEnergy has been around nearly a decade).

In our own programs, we see this clearly:

• SUSTAIN® for hydraulic fracturing delivered 20% more oil and 15% more gas in the first six months of production, with a return on investment greater than 10× and payout in under one month in Delaware Basin wells compared with untreated offsets.
• STIM® for well remediation has generated up to 70% production increases above baseline forecasts in producing wells.

The difference is not a different rock or a more aggressive frac, or even “magic molecules”. The difference is novel chemistry engineered for the pore-scale environment  actually completing. That means surfactant systems tuned for:

• Nanopore access. Many shale pore throats are below 100 nm. Microemulsion systems with small hydrodynamic radii have been shown to deliver better imbibition and oil recovery under those conditions.
• Wettability shifts. In tight-oil systems that are initially oil-wet, shifting toward more water-wet behavior can significantly reduce residual oil saturation and improve spontaneous imbibition during shut-in periods.
• Capillary pressure reduction. Because capillary pressure scales with interfacial tension and contact angle, lowering both directly reduces the threshold pressure required for fluids to move through nanopores.
• Compatibility with in-situ conditions. Matching surfactant chemistry to reservoir brine salinity, hardness, oil composition, and mineralogy is essential to avoid phase separation, precipitation, or unwanted emulsions and to maintain performance at reservoir temperature.

In short: mechanical design creates contact; chemistry determines how much of the contacted hydrocarbons can be displaced and moved to the surface.

Critical for the Future

As operators head into 2026, the pressures are familiar:

• Tighter capital budgets.
• Consolidation-driven portfolio changes.
• Higher expectations for every completion dollar.

At the same time, the “easy” mechanical wins, longer laterals, more stages, more sand and water, have largely been captured. New rigs and new locations are more expensive and often of lower average quality than the core inventory that built the first wave of shale growth.

Chemical efficiency is emerging as one of the most practical and scalable levers available:

• It improves recovery from existing rock rather than relying solely on new drilling.
• It can enhance performance of new wells and legacy wells alike.
• It adds value without requiring proportionally more rigs, pads, or surface footprint.

The resource is there. The opportunity is clear. And the next chapter of unconventional performance will be defined not just by how we drill and complete, but by the chemistry we deploy to unlock more of what these reservoirs already hold.

The industry is finally catching up to what optimized chemistry can deliver.

We’re not starting now, we’ve been building toward this moment for years and proving it, well by well.

References

1. Blas, J. (2025). Shale Oil’s Next Revolution Should Worry OPEC. Bloomberg Opinion, November 20, 2025. Bloomberg
2. NETL / U.S. DOE (2014–2015). Improved Characterization and Modeling of Tight Oil Reservoirs. Project FE0024454; presentation noting typical recovery factors of roughly 3–10% in tight oil plays such as the Bakken. netl.doe.gov
3. JPT (2019). Management of Enhanced Recovery Technologies for Unconventional Oil Reservoirs. Journal of Petroleum Technology article summarizing primary recovery in U.S. shale plays as generally less than 10% (often 2–8%). JPT
4. EPCM Holdings (2021). Enhanced Oil Recovery in Shale. Technical overview noting that recovery factors across 28 U.S. tight oil plays are typically below 10%, highlighting the scope for EOR in shale. EPCM
5. USEA / Advanced Resources International (2020). Shale Oil Recovery, Storage, and CO₂-EOR Study.Assessment of tight oil in-place resources and the impact of modest improvements in shale oil recovery efficiency. adv-res.com
6. Habibi, A. et al. (2017). “Oil Interactions in Tight Rocks: A Montney Case Study.” Fuel. Discusses oil–rock–brine interactions and cites primary recovery factors on the order of 3–10% for unconventional resources. ScienceDirect
7. Li, L. et al. (2017). “Nanopore Confinement Effects on Phase Behavior and Capillary Pressure.” Journal of Natural Gas Science and Engineering. Examines how nanopore confinement impacts capillary pressure and fluid distribution in tight formations. ScienceDirect+1
8. Jiang, W. et al. (2024). “Study on the Effects of Wettability and Pressure in Shale Matrix Nanopore Imbibition During Shut-in Process by Molecular Dynamics Simulations.” Molecules, 29(5), 1112. Shows how wettability and pressure influence imbibition and recovery in shale nanopores. MDPI
9. Chen, W. et al. (2024). “A Comparative Study of Surfactant Solutions Used for Enhanced Oil Recovery.” Open-access study demonstrating how different surfactants reduce interfacial tension, alter wettability, and enhance imbibition. PMC+1
10. Patil, P. D. et al. (2018). “Surfactant Based EOR for Tight Oil Unconventional Reservoirs.” URTeC-2896289 / OGWA proceedings. Details tailored surfactant formulations for wettability alteration and improved oil recovery in tight reservoirs. OnePetro+1
11. Mukhina, E. et al. (2021). “Enhanced Oil Recovery Method Selection for Shale Oil Reservoirs.” Energies, 14(18), 5743. Compares EOR methods (including surfactant solutions) and reports recovery improvements in shale core-flood experiments. PMC
12. Xue, J. et al. (2025).“Analytical Modeling and Comparative Analysis of Capillary-Driven Imbibition in Nanoporous Media.” Explores capillary-driven flow based on Young–Laplace relationships and implications for tight-rock recovery.