A surfactant used in enhanced oil recovery has one primary job: lower the interfacial tension between oil and water enough that the remaining oil will move. Glycoside surfactants, and sophorolipids in particular, are interesting here because their structure combines a sugar head group with a lipid tail, which gives them a low interfacial tension and a tolerance for salinity and temperature that many conventional surfactants do not have. That tolerance is what makes them candidates for the reservoir conditions where a cheaper surfactant stops working.
Product referenced in this article
Biosurfactant Viscosity Reducer for Heavy Oil — application notes, specification table and document downloads for this range.
What interfacial tension does and why the number matters
Oil sits in the pore space of rock as discrete ganglia, held in place by the capillary forces at the oil-water-rock contact. The capillary force is proportional to the interfacial tension, and it is what keeps the oil from moving when pressure is applied. Reducing the interfacial tension lowers that force, and at a sufficiently low value the oil ganglia can deform and mobilise, which means the oil flows toward the production well instead of staying where it is.
For that reason the figure that gets quoted and the figure that matters are the same one. Our published operating value for interfacial tension with this type of biosurfactant is in the region of 10 to the power of minus three millinewtons per metre, which is the range conventionally treated as the threshold for mobilising trapped oil. It is a published figure with a stated application, and we will re-check it against your specific oil and brine rather than quote it unchanged for a reservoir we have not seen.
What makes sophorolipids different from conventional surfactants
Most oilfield surfactants in commercial use are petrochemical-derived and work by partitioning at the interface in a way that depends on the salinity and temperature of the brine. As the salinity rises, the solubility of the hydrophobic tail changes, and above a certain point the surfactant is salted out of the aqueous phase and aggregates in the oil phase. The practical effect is that a surfactant that performs well in a bench test on fresh water can lose most of its effect in formation brine.
Glycoside surfactants have a sugar moiety as the hydrophilic head. Sugars are highly polar and tolerate high ionic strength without the same loss of solubility, and a glycosidic bond is stable across a wide pH range. That gives two practical advantages in the field: retention of activity at formation salinity, and a narrower pH sensitivity, which matters because produced water is often more acidic than the injection water people specify with.
Temperature, and what happens to a surfactant that fails
Temperature tolerance follows from the same chemistry. A sulfate or sulfonate head group degrades at elevated temperature, and the product loses activity in the reservoir rather than in the test. Glycosides are considerably more stable in this respect, which is the reason the class is discussed for steam-assisted and higher-temperature reservoirs where conventional chemistry is not viable.
It is worth being precise about failure modes, because they look similar from the surface. A surfactant that has degraded in the reservoir produces no change at all. A surfactant that has been adsorbed onto the rock produces a change that decays over the first few days as the concentration in solution falls. A surfactant that has partitioned into the oil may still be active but is no longer available to lower tension in the water phase. Only the first of these is a temperature problem, and the distinction matters for deciding whether temperature is the constraint or adsorption is.
Choosing between a surfactant and a viscosity reducer
Two different problems get grouped together under enhanced oil recovery, and they are solved by different products. Surfactant work lowers the interfacial tension so that capillary forces holding oil in place are reduced. Viscosity reduction addresses the fluid itself: heavy oil is difficult to push because it does not flow readily, and a polymer or a biosurfactant that reduces its apparent viscosity makes the fluid mobile.
They are combined in some fields, and a biological product can act on either. Sophorolipids are more usually discussed for the surfactant role; the heavy-oil products in our range are formulated for the viscosity role. The way to tell which you need is to establish whether the oil is immobile because nothing is pulling it out or because the fluid being injected is too thick to move it. That is a simple rheological comparison and it settles the specification much faster than a general enquiry about enhanced recovery.
What to send us so we can respond usefully
Four things, and with them we can return a specific recommendation rather than a general description. The oil properties: viscosity at reservoir temperature, and the wax or asphaltene content if the oil is crude rather than a refined stream. The brine: salinity, and the pH if it is known. The reservoir: temperature, and whether the injection is secondary or part of a waterflood. And the target: what the current recovery is and what you are trying to change.
Two questions worth asking a supplier before a trial. Whether they have tested against your oil and your brine rather than a standard reference fluid, and whether the reported interfacial tension was measured at reservoir temperature and salinity. Both are reasonable requests and a supplier who cannot answer them has not done the work. We are happy to answer both for the products we supply, and we will say plainly when a case needs field trial data we do not yet have.
Frequently asked questions
- What interfacial tension can a biosurfactant achieve?
- Our published operating value for this class of glycolide surfactant is around 10 to the power of minus three millinewtons per metre, which is the range conventionally treated as the threshold for mobilising trapped oil. The figure depends on the oil, the salinity and the temperature, so we re-check it against your specific fluid pair rather than quoting it unchanged.
- Are sophorolipids better than petrochemical surfactants for oilfields?
- Neither is better in the abstract; they suit different conditions. Petrochemical surfactants are cheaper and often effective at low salinity and moderate temperature. Glycoside surfactants tolerate higher salinity, a wider pH range and higher temperature, which is what makes them candidates where conventional chemistry stops working. The right choice depends on your brine composition and reservoir temperature.
- Can a biosurfactant replace a polymer in a waterflood?
- Generally not as a like-for-like substitution, because they act on different properties. A polymer improves mobility ratio by changing fluid rheology; a surfactant lowers interfacial tension so that capillary forces holding oil in place are reduced. Some biological formulations address the viscosity role, and combining roles is possible, but the specification should follow the problem: if the oil is immobile because nothing pulls it out, that is an interfacial tension problem; if the injected fluid is too thick, that is a rheology problem.
- How much biosurfactant is needed for an enhanced oil recovery trial?
- It depends on the reservoir, the oil and the injection scheme, and a figure given without those three is not a useful answer. What we can commit to is this: send the oil viscosity at reservoir temperature, the brine salinity and pH, the reservoir temperature and the current recovery, and we will return a specific recommendation with a starting concentration. For a first field trial we would rather agree the measurement plan in advance than quote a concentration nobody has checked.