Biosurfactants are having a moment: Here’s the physics behind why they work and where
MEGAN PEARL and MARTIN SHUMWAY, Locus Bio-Energy
Over the last decade, the U.S. shale industry has optimized itself into a ceiling, Fig. 1. Laterals have grown longer, stage counts have increased, and proppant loading and fluid volumes have climbed steadily. Over the same period, capital discipline has tightened under sustained investor pressure, with operators seeking to minimize drilling and completion costs. By most measures, operators are doing more things right than ever before.
Even so, recovery factors across unconventional plays have remained stubbornly fixed in the 5% to 15% range—a number that has barely moved, despite everything the industry has thrown at it. When executives at CERAWeek this year acknowledged that operators routinely leave roughly 90% of original oil-in-place, they were not describing an emerging challenge. Instead, they were finally putting a number on a problem the industry has been navigating for years.
Drilling and completions engineering is fundamentally an access problem: how do you create a sufficient fracture network to establish a connection between the wellbore and the reservoir? That problem has been addressed, refined and re-addressed to a point where meaningful incremental gains are increasingly difficult to find. However, what it does not address is whether or not oil can move, once that connection is made.
In tight unconventional formations, where pore throats are measured in nanometers, the forces holding oil against the rock surface are not overcome by a pressure differential alone. Interfacial tension, capillary pressure and wettability determine whether oil detaches from pore walls, migrates through the reservoir pore network and enters the fracture system, where production can begin. These are surface phenomena that do not respond to increasing mechanical stimulation, Fig. 2.
This is a fundamental problem that the broader operator community—from asset managers evaluating development programs, to reservoir engineers reconciling model predictions with actual decline curves—has yet to frame in a way that leads to different thinking or more elegant solutions. In many cases, the gap between what completion models predict and what wells actually deliver is governed by surface‑physics effects, rather than access to the rock. Chemical interventions like surfactants are often intended to address this gap. The fracture network is in place, but much of the oil has not been mobilized. Also, when surfactants are used, the chemistries most commonly deployed are not designed to address the pore‑scale constraints that ultimately control oil mobility.
WHY CONVENTIONAL SURFACTANT CHEMISTRY HAS REACHED ITS LIMIT
For certain operators, hydraulic fracturing surfactants have been a standard component of completion fluid design for decades. However, many operators have eliminated surfactants in the interest of aggressive cost-cutting initiatives. The underlying rationale to include surfactants in hydraulic fracturing is sound in principle and grounded in physicochemical properties: reducing interfacial tension between fluid phases and changing wetting dynamics at solid surfaces is known to enhance fluid distribution, reduce water blocks, and improve flowback efficiency. The issue is not with the concept but with how chemical interventions are designed, relative to reservoir dynamics and within the boundaries of what most conventional surfactants can achieve in tight unconventional formations.
For example, conventional surfactant micelles—the small molecular assemblies that carry surface-active chemistry into the formation—typically measure between 10 and 100 nanometers. Shale pore throats in formations like the Delaware basin’s Wolfcamp formation or the Williston basin’s Middle Bakken formation range from 3 to 40 nanometers, limiting surfactant access to oil across the distribution of pore sizes in ways that could be contributing to the inefficiencies observed when deploying conventional surfactants. This surface-active chemistry is concentrated in the macropore fraction and the near-wellbore zone, delivering a legitimate but limited benefit and leaving the tighter portions of the pore network untouched. The production response that follows—a strong early rate that normalizes faster than desired—is a predictable consequence of chemistry that never reached most of the oil.
There is a second limitation that compounds the first. Most conventional frac surfactants are designed around a single mechanism: IFT reduction at the oil-water interface. That is one component of the mobility problem in a tight reservoir, but it is not the whole problem. Oil-wet rock surfaces hold hydrocarbons tightly through weak electrostatic and van der Waals interactions between the hydrocarbon molecules and the mineral surface—forces that persist, regardless of interfacial tension reduction between fluid phases. A surfactant system optimized solely for IFT reduction addresses one variable in a multi-variable system and delivers results accordingly. The production bump is real. However, the sustained uplift that would indicate genuine pore-scale mobilization is not there, because the chemistry deployed did not address all constraining variables.
Indeed, not all surfactants or blends thereof are created equally. Biosurfactants, a novel class of surfactants produced through fermentation, are characterized by a molecular architecture distinct from petrochemical-derived surfactants, and they address these phenomena differently. A key differentiator is that they form micelles in the range of 3 to 5 nanometers, supporting deeper penetration and allowing the chemistry to operate across a larger distribution of pore sizes, compared to conventional surfactants.
Another signature characteristic is the many active sites per molecule, supporting action across multiple mechanisms simultaneously: reducing interfacial tension between oil and water phases, shifting wettability of rock surfaces from oil-wet to water-wet, penetrating and dispersing organic deposits, and suspending mobilized solids during flowback. These mechanisms are not sequential. They operate concurrently throughout the pore network, and they continue operating long after conventional surfactants fade.
That last condition—reservoir persistence—is where the survivability question becomes important. Produced water in tight unconventional formations is chemically aggressive: total dissolved solids in Bakken brine commonly exceed 250,000 parts per million, with divalent ion concentrations that can collapse conventional surfactant systems well before they reach meaningful dilution. Laboratory measurements confirm that biosurfactants maintain a lower critical micelle concentration in produced water from target formations, compared to conventional surfactant systems under the same conditions. A chemistry that remains surface-active at low concentration, as it dilutes during flowback, continues altering wettability and mobilizing hydrocarbons throughout the production period. One that deactivates early delivers near-wellbore cleanup and little else, which is the profile most operators have come to accept as normal from surfactant chemistry.
A recent Delaware basin frac trial puts that difference in quantitative terms. The operator led a third-party qualification study comparing 20 commercially available surfactants under actual reservoir conditions before going to the field. In the study, the biosurfactant-based formulation outperformed all other surfactants across performance objectives and price. Over a 12-month period in the field, the treated wells produced up to 20% more oil and 15% more gas than untreated offset wells, achieved payout in under one month and delivered over 12x the returns. The water-oil ratio for treated wells was significantly improved versus untreated wells, with the improvement sustained over the full monitoring period. A year of proportionally more oil per barrel of water points specifically to durable wettability alteration in the rock matrix—a formation-level response that cleanup effects alone, which dissipate within weeks as chemistry dilutes, cannot produce.
THE SAME PHYSICS GOVERN EVERY STAGE OF THE PRODUCTION LIFECYCLE
The mechanisms that drive improved oil recovery in new completions—pore-scale IFT reduction, wettability alteration and organic solid dispersion—do not stop being relevant when a well matures, Fig. 3. They become more critical. As reservoir pressure declines, and the most accessible oil has been produced, what remains is held by the same capillary forces that biosurfactant chemistry is designed to overcome, compounded by years of organic and inorganic solid accumulation along the wellbore and in the near-wellbore zone.
Gas huff-and-puff, the most common intervention in this situation, restores reservoir pressure but does not alter adhesion, does not clear organic deposits, and does not change the wettability conditions that determine whether residual oil can migrate toward the wellbore. It produces formation pressure but lacks hydrocarbon mobility, which is why the production response from huff-and-puff so often looks like a brief recovery, followed by a return to the prior decline rate.
Biosurfactant-based treatments address what huff-and-puff cannot. In a Middle Bakken pilot program on horizontal wells that had been producing approximately 20 bopd, biosurfactant treatments resulted in a 70% increase over forecast production for more than 4 months, making several of the wells prime candidates for refracturing. Additionally, only 20% of the total treatment volume returned as produced water on flowback, suggesting deeper penetration and more durable wettability alteration than near-wellbore fluid displacement would produce. The application was rig-less—pumped through the tubing-casing annulus with a shut-in period of less than eight days before wells returned to production—presenting a significant economic advantage over interventions that require rig time and long shut-in times.
Post-treatment fluid analysis confirmed what the production numbers implied. IFT of produced crude remained measurably below pre-treatment levels through three months of flowback, demonstrating that the chemistry retained surface activity in the reservoir at concentrations sufficient to continue altering interfacial conditions. Paraffin content in produced crude increased post-treatment, from 0.8% to 2.3%, which reflects the multifunctional behavior at work: the biosurfactant mobilized paraffin that had deposited downhole, maintained dispersion of suspended paraffin during flowback, and produced a more compositionally complete crude oil with heavier hydrocarbon fractions that had been accumulating in the formation. Across 15 horizontal Bakken wells in the expanded program, 11 produced above forecast, with the underperforming wells attributed to geomechanical delivery issues that concentrated treatment fluid in depleted heel zones, rather than distributing it across the producing lateral—a placement problem rather than a chemistry failure.
The same surface phenomena extend well beyond the reservoir boundary, and recognition of that connection changes how the economics of biosurfactant chemistry should be evaluated. In gathering lines and transportation pipelines, paraffin and asphaltene deposition are driven by the same surface adhesion mechanisms active in the pore network: heavier organic molecules precipitate as crude cools and pressure drops along the line, adhere to pipe walls, and accumulate over time.
Biosurfactant chemistry keeps those molecules in suspension in the bulk crude under changing temperature and pressure conditions, maintaining flow capacity rather than addressing deposition after it has already occurred. In produced water disposal, dispersion and suspension of solids, along with wettability alteration, maximize injection volumes while minimizing injection pressures. The example extends to storage and tank cleaning. The penetration and dispersion behavior that mobilizes oil from nanopore surfaces also plays out in the penetration and suspension of heavy tank bottom sludge. Addressing these issues directly reduces cleaning time and returns tanks to revenue service faster.
These benefits also reduce operational complexity and improve efficiency. In acid stimulation programs across more than 1,000 wells in California, operators were able to replace individual components—including solvent, surfactant and anti-sludge additives—with a single biosurfactant-based microemulsion. The result was a simpler job design, an 80% reduction in ancillary chemical volumes and average production increases of 70%.
Each example presented highlights various aspects of an interfacial problem. Tuned chemical interventions act on the physics of the interface wherever it appears in the production system, whether that interface is between oil and water in a nanopore; between a hydrocarbon deposit and a pipe wall; or between a sludge layer and the steel floor of a tank. The industry typically procures frac chemistry, EOR chemistry, flow assurance chemistry and produced water treatment as separate solutions—often from different vendors, on different procurement cycles, and under separate budgets. This fragmentation obscures the shared, mechanism-level physics and prevents any single decision-maker from assessing the full value of an integrated chemistry platform that addresses all of them.
That structure has a real cost—one that shows up not in the chemistry line item but rather, in total lifting economics, in decline curves that steepen faster than they should and in the gap between what assets were expected to produce and what they deliver over time.
Several major operators have been publicly discussing surfactant chemistry. During CERAWeek 2026, ConocoPhillips described significant first-year cumulative production uplift from surfactant injection during hydraulic fracturing of new wells. Diamondback—the Permian’s largest independent—also deployed surfactants across sixty wells in the second half of 2025 as it focused on increasing production and explicitly working to understand which variables were driving results. Chevron has expanded its surfactant pilot programs beyond the Permian into multiple operating areas. Taken together, what these programs reflect is an industry beginning to recognize that surfactant chemistry is relevant at multiple points in the production lifecycle—not only as an EOR-specific intervention but also as a mechanism-level tool that addresses the same interfacial constraints whether applied at the frac stage, during production, or in mature well intervention. That recognition is what has shifted. This technology—and the field evidence supporting it—has been there for years. The trick lies in understanding how to balance the competing phenomena downhole with chemical interventions.
The 90% of original oil in place that stays in the ground is not staying there, because operators have failed to optimize their completions. It is staying there, because the dominant optimization effort of the last two decades was aimed at access, and access was never the binding constraint on recovery. Surface phenomena have been setting the rules at every stage of the production lifecycle, from the first frac stage through the separator. The chemistry capable of acting on those phenomena at the nanopore scale has been available and field-proven long enough that the remaining question is organizational, not technical. The operators who align their chemistry decisions with their recovery objectives across the full-well lifecycle, rather than one application at a time, are the only ones who will move that recovery factor.
MEGAN PEARL is vice president of Global Technology at Locus Fermentation Solutions, a position she has held since December 2025. Previously, she was vice president of Technology at Locus Bio-Energy Solutions, the oil and gas division of Locus Fermentation Solutions, from January 2023 to December 2025. Prior to that position, Ms. Pearl was director of Technology from January 2022 to January 2023. Previous to her tenure at Locus Fermentation Solutions, she worked at Halliburton for over nine years, serving in various positions of increasing responsibility. Ms. Pearl graduated with a bachelor’s degree in chemistry from Illinois Wesleyan University in 2007 and then completed a doctorate in Analytical Chemistry from the University of South Carolina in 2011. She also earned an MBA degree from the University of Texas at Dallas in 2017.
MARTIN SHUMWAY is senior vice president at Locus Bio-Energy, the oil and gas division of Locus Fermentation Solutions. He has held this position since June 2023. Before that, he was technical services director at the company for over six years, dating back to March 2017. Previous to that, he was an engineer/geologist and consultant at several oil-and-gas-related firms for approximately 25 years, including several years at his own company. Mr. Shumway earned a bachelor’s degree in civil engineering from The Ohio State University in 1998. He then received a master’s degree in civil engineering during 2000, also from The Ohio State University.
