Biosurfactants for heavy oil viscosity reduction work by lowering the interfacial tension between the oil and the water being injected, and by keeping the fluid mobile where a polymer would be adsorbed onto clay or broken by shear on the way down the well. They are worth screening in heavy and extra-heavy oil reservoirs, in waterflood and injection wells, and in enhanced oil recovery trials where polymer retention and shear degradation explain why the previous programme underperformed. They are not a substitute for a polymer where the real problem is that the injected fluid is too thick to push through the rock.
This note is written for production engineers and for buyers who have already run a polymer flood on a heavy oil reservoir and seen the response fade. It covers what a biosurfactant actually does in the formation, why polymers behave as they do in the same rock, and the questions that decide whether a biological route is worth a trial at all.
Product referenced in this article
Biosurfactant Viscosity Reducer for Heavy Oil — application notes, specification table and document downloads for this range.
What viscosity reduction actually does
Two different mechanisms get sold under the phrase viscosity reduction, and confusing them leads to the wrong product being specified. The first is rheological: reducing the apparent viscosity of the fluid so it can move through the pore space at a pressure the well can actually deliver. The second is interfacial: reducing the tension at the oil-water contact so the capillary forces holding residual oil against the rock are weakened. A biosurfactant acts mainly through the second mechanism, and our note on sophorolipid biosurfactants in oilfield applications covers the chemistry and the temperature limits that decide whether it survives the trip into the formation.
Why heavy oil behaves differently
Heavy oil is not simply light oil that is thicker. It contains more wax and more asphaltene, and those fractions make the behaviour temperature-sensitive: as the reservoir cools, wax comes out of solution and apparent viscosity rises steeply. It also changes the engineering around the treatment. Higher pressure is needed to inject at all, which means more aggressive surface pumping, which means more shear on anything injected. Heavy oil fields are also frequently clay-bearing, so both failure modes that matter for a chemical flood are more likely in exactly the reservoir where the fluid is hardest to move.
Interfacial tension and the number that decides whether oil moves
Oil sits in the pore space as disconnected ganglia held against the rock by capillary force, and that force is proportional to the interfacial tension between oil and water. Lower the tension and the ganglia deform more easily under the pressure the injection system can supply. The published figure for our rhamnolipid grade is an oil-water interfacial tension taken from 43 down to 1 millinewton per metre, the range conventionally treated as the threshold at which trapped oil becomes mobile. It is a published number with a stated application, not a universal constant, and it moves with the oil, salinity and temperature.
Where polymers lose: retention on the rock
Retention is the first reason a polymer programme disappoints in a heavy oil reservoir. Polymer molecules adsorb onto the surface of clay minerals, and the ones that stick are no longer available to work. Concentration in solution falls with distance from the injection well, so the front arrives at the target interval already weaker than what was mixed, and the treated zone has a different mobility from the untreated rock around it, so fluid starts channelling. This is a rock problem rather than a product problem, and no reformulation of the polymer fixes it.
Where polymers lose: shear degradation on the way in
Shear degradation is the second failure, and it happens entirely above ground. Pumps, chokes, blender lines and the completion impose mechanical stress on the polymer chain until it breaks. The result is a fluid that still looks like polymer in the tank but has lost the viscosity it was specified for, and the effect scales with the pressure drop the surface equipment handles. Separating the two failures gives the most useful diagnosis: retention shows up as a treatment that works near the injector and decays with distance, while shear degradation shows up as a weak response from the first day, even close to the well.
| Failure mode | Where it happens | How it shows up |
|---|---|---|
| Retention on clay | In the formation | Response decays with distance from the injector |
| Shear degradation | In the surface equipment | Weak or absent response from the start |
| Temperature failure | In the formation | No response anywhere, including near-wellbore |
| Insufficient tension reduction | In the formation | Response present but below the target |
What a biosurfactant does instead, and what it does not fix
The advantage of a biosurfactant here is structural rather than magical. It is a smaller molecule than a high-molecular-weight polymer, so it is less likely to be adsorbed and less likely to be broken by shear, and it survives in the formation long enough to act at the interface. Because it partitions at the oil-water contact rather than thickening the water phase, it is complementary to mobility control rather than a substitute for it. What it does not fix matters equally: it does not address a reservoir where the injected fluid is too viscous to enter the formation at all, nor a wellbore packed with wax.
Screening: when this route is worth a trial
The screening question is not whether biosurfactants work, but whether this reservoir has the combination of properties that lets the mechanism act. Temperature sets the ceiling, because a product outside its thermal tolerance degrades in the formation and produces no response at all. Salinity sets the range over which the surfactant stays soluble in the aqueous phase, and produced water is often saltier and more acidic than the injection water people specify with. Rock composition decides how much of the product survives the trip, and clay content is the number worth asking for. Injection conditions decide how much shear the molecule sees before it arrives. Our guide to deciding whether bio-based oilfield additives fit your well or reservoir sets out the wider screening logic.
Where our products sit
Our biosurfactant viscosity reducer for heavy oil is the product for this application, formulated for heavy and extra-heavy oil reservoirs, interfacial tension management, and waterflood and injection wells. Where the mechanism you are relying on needs a stronger temperature and salinity profile than the general product offers, our rhamnolipid biosurfactant is the grade to look at, and our lipopeptide biosurfactant the alternative where foam stability in the injection fluid matters.
What we do not promise
We do not quote a percentage viscosity reduction, because the number depends on the oil, the rock, the temperature and the injection scheme, and any figure offered without those four is borrowed from somebody else’s reservoir. We do not quote a fixed timeline either. The honest expectation is improved mobility and better oil release at the margin, on an interval that has not already been swept. It does not replace mobility control where mobility control is what the reservoir is short of. We are a National High-Tech Enterprise with 10+ granted patents, we run our own fermentation pilot plant, and we are ISO9001, ISO14001 and ISO45001 certified with a certificate of analysis per production batch.
How to judge whether it is working
Monitor what moves before the oil rate does. Injection pressure response, the interfacial tension measured on produced samples, and the viscosity of the produced blend all change ahead of the production curve, and they tell you whether the product is active and reaching the target interval. If the produced fluid shows no change in tension while the programme is running, the mechanism is not acting and the trial should be reviewed rather than extended. Keep a comparison where the field allows it: a single-well before-and-after comparison on a heavy oil reservoir is usually a comparison of two different weather patterns.
What to send us for a screening opinion
Send the oil viscosity at reservoir temperature with the wax and asphaltene content, the brine salinity and pH, the reservoir temperature, the injection scheme and completion, and the current recovery with what you are trying to change. Add what has already been tried and what went wrong. Our technical team replies with a screening view: whether the temperature and salinity envelope admits the mechanism you would need, how much retention is likely to remove, what a concentration and monitoring plan would look like, and where a polymer or a purely mechanical answer would be more defensible.
Frequently asked questions
- How is biosurfactant heavy oil viscosity reduction different from polymer flooding?
- A polymer is retained by the rock and degraded by shear on the way in, so a large part of what is injected never reaches the oil it was meant to move. A biosurfactant is a smaller molecule that partitions at the oil-water interface, so less of it is lost to retention and less of it is broken by the pumping equipment. It acts on interfacial tension rather than on bulk rheology, which makes it a different tool rather than a better polymer. Where the injected fluid is simply too thick to enter the formation, a polymer remains the more direct answer.
- What causes polymer retention and shear degradation in heavy oil reservoirs?
- Retention happens because the reservoir rock, particularly clay-bearing formations, adsorbs the polymer onto its surface. The molecules that would have travelled ahead of the front are held back, and the effective concentration falls with distance from the injection well, so the treated zone also has a different mobility from the untreated rock around it. Shear degradation is separate and happens in the surface equipment: pumps, chokes and blender lines break the chain, and the viscosity the polymer was bought for is lost before the fluid reaches the formation. Heavy oil makes both worse.
- How much biosurfactant does a heavy oil treatment need?
- There is no figure we can publish that would be meaningful for your reservoir. The concentration that matters is what is left in solution after retention losses, and that depends on the clay content of the rock, the salinity of the brine, the temperature and the injection rate, none of which we can see from outside. Send the oil viscosity at reservoir temperature, the brine composition, the reservoir temperature and the injection scheme, and we will come back with a starting concentration and a measurement plan agreed before anything is pumped.
- Which reservoirs are a poor fit for a biosurfactant viscosity reducer?
- Two cases rule it out. The first is a reservoir where the oil is immobile because nothing is pulling it out rather than because the injected fluid is too thick, which is an interfacial tension problem that a viscosity reducer does not solve on its own. The second is a formation with heavy clay content and very high specific retention, where most of the product would be adsorbed before it could do any work and the economics would not hold. Beyond those, a reservoir outside the temperature and salinity tolerance of the product is simply not a candidate.
- What data do you need before quoting a biosurfactant programme?
- Five items, and with them our application engineers can return a specific recommendation rather than a general description: the oil viscosity at reservoir temperature together with the wax and asphaltene content, the brine salinity and pH, the reservoir temperature, the injection scheme and how the well is completed, and the current recovery with what you are trying to change. Add what has already been tried. We are a National High-Tech Enterprise with 10+ granted patents and our own fermentation pilot plant, so a blend can be reviewed against your data rather than taken from a catalogue.