FAQs

Why are surfactants such a hot topic right now? What brought these type projects into the money?  It is a hot topic now because the use of surfactant EOR in shale oil wells represents one of the best opportunities to boost production from existing shale wells.   It is a relatively low cost EOR approach vs. cyclic gas injection, or refracs.    These projects have been “in the money” since the initial field tests starting ~ 2020.  What is driving the interest now is the somewhat poor recovery factor  from ALL shale wells (5-10% OOIP), and the growing realization that shale operators are rapidly running out of drilling opportunities in onshore US.  Big operators are exploring surfactant EOR in shale wells and some are already deploying. 

What do breakeven economics look like for using EOR? Do you need $70 WTI? Higher/lower?   We have treated some wells that have incremental barrel UTC on the order of $20/bbl.  This technology does not NEED high oil price, but it obviously helps the economics if oil price is higher.

How do shale-specific properties (e.g., ultra-low permeability, nanopore structure, organic matter) fundamentally limit or enable EOR effectiveness compared with conventional reservoirs?   Those properties are challenge for sure, but they are also the reason that a chemistry-based EOR approach is best.   It is very expensive to try to introduce more mechanical fractures in an existing well, and reservoir energy is rapidly depleted in essentially all shale oil wells.   Using surfactant adsorption thermodynamics to change rock wettability to water wet from oil wet drive oil expulsion from this tight rock – that is the key.   Using surface chemistry to move the oil out of the really tight rock is what makes it work.   It actually doesn’t work as well in high perm, large pore structures.

What role do wettability and capillary forces play in fluid recovery from shale nanopores, and how well are these mechanisms currently understood?   Wettability alteration and changing capillary forces are the key, and that is generally  well understood.  There are some parties that insist that reduction of oil-water IFT is critical.   Specifics related to surfactant systems and how to use them are less well understood, except for a few experts in this area. 

How does heterogeneity at the nano- to micro-scale impact sweep efficiency in shale EOR processes?   The general approach in shale wells is somewhat different than in conventional (higher perm) reservoirs.  The goal is not necessarily to “sweep” oil from one well toward another, but rather to release oil from tight matrix into “less tight” volumes where existing reservoir energy can complete the convection of oil to the wellbore. With that in mind, the “higher perm zones” and certainly the fractures (all of them, natural, induced, induced/propped) have a key role to play as the conduits back to the wellbore.

Which EOR mechanisms—miscibility, swelling, viscosity reduction, interfacial tension reduction—are most relevant in shale, and why?  Wettability alteration is key.  The rest in that list don’t matter so much – at least for surfactant EOR.    Miscibility, liquid phase swelling, viscosity reduction, and IFT reduction are more important for EOR technologies where you are purposefully trying to add reservoir energy (like cyclic gas injection).   If the rock is oil wet, you MUST deal with wettability first and foremost, otherwise you are going to literally leave oil on the table.

How viable are gas-based EOR methods (CO₂, rich gas, N₂) in shale compared to chemical or thermal methods?  They are quite expensive vs chemical methods.   We have not looked closely at thermal methods as shale oil is generally high API, not viscous, and so thermal methods don’t help a lot.

What reservoir characteristics make an ideal candidate for surfactant EOR? Does the Permian or another basin meet this criteria?   Oil wet rock, reasonably strong GOR remaining, temperatures and salinities that are amenable to current surfactant systems designed to flip wettability.   Permian and most all the other US shale basins DO fit these criteria.

What distinguishes cyclic gas injection (“huff-and-puff”) from continuous injection in shale, and when does each make sense?   The process is obviously different.  For both, the key is gas recovery.  Using gas to re-energize shale reservoirs is a tricky proposition. If you don’t recover enough of the gas, the economics go south. 

How do existing hydraulic fractures influence EOR outcomes, and what fracture characteristics matter most?   High specific matrix surface area is key.   The more “bushy” the fractures (of any kind), the more oil rich matrix face is available, and the more incremental bbls you can attack.

To what extent does inter-well communication enhance or diminish EOR performance in pad developments?   We have seen instances where well to well communication can  help, for instance, surfactant treatment of a depleted parent well prior to a pressure increasing event can result in improved recovery from an old well.    Obviously, in some basins frac hits from nearby completions can have a deleterious effect on a parent well (surfactant stimulated or not).

Are current completion designs optimized for EOR, or would different fracture strategies be required?   For the most part, completion designs are generally aimed at maximizing fracture surface area (area available for oil flux from the tight matrix).   We wouldn’t say they are “optimized” for EOR by any stretch, but they are trying to achieve a situation in the reservoir that IS conducive to (particularly) surfactant EOR.

Why have lab-scale and pilot EOR results in shale often failed to scale predictably to full-field applications?   We are still pinning down the exact design variables in each shale basin.   The economics do not work out on every well injected.  There are quite a few operators who are trying things, but without much technical know-how about surfactants and what conditions need to be achieved to get this to work consistently.   Most US operators focus is “do a whole bunch of stuff and look at statistics” (less so for the IOC’s).   EOR is more about understanding first principles, pinning down hard-to-know parameters in the lab, or via models, and then testing in the real reservoir and looking for signals in the flowback data. 

What performance metrics best indicate early EOR success or failure in shale plays?  Obviously oil rate post stim vs pre-stim.  Metrics related to making sure the available rock surface is fully treated are critical, but not many realize this at this point.

How sensitive are EOR outcomes to timing—specifically, when injection begins relative to primary depletion?   The project returns on a given well can be high almost regardless of where a particular well IS on its decline.   What is different is simply NPV and cash flow.   Newer wells, with high production rates can be stimulated and they will generate high incremental bbl rates, making them more material.  So for example, treating a single well producing 100 bopd might have equivalent economics to a  project treating 10 wells that are all doing 10 bopd.

Under what oil price and cost conditions does shale EOR become economically compelling?   It can work well even at fairly low oil price (meaning low cost services too).  We think it is economically compelling even at $50/bbl. 

How should operators think about the trade-off between accelerated recovery versus ultimate recovery in shale EOR projects?  We occasionally hear “pushback” that this technology simply accelerates production of what would ultimately be recovered later.   We have evidence that use of surfactants actually frees some heavy oil components that do not appear in the oil arising from the initial completion, and that does point to the likelihood that this technology is producing some bbls you won’t get with the usual drilling/completion approaches.

What are the biggest gaps or uncertainties in current shale EOR simulation models?  How to model the imbibition process, from adsorption to oil expulsion?   How to model the fracture network?   There are just too many adjustable parameters at this stage that need to be pinned down with lab and field data. At this stage, you can make a model say about anything you want.  By nailing down the uncertainties, this can become a predictive tool. 

What are the biggest drawbacks for using EOR methods like surfactants?   There are not many.  If you can get the economics working, there are few drawbacks.  It is relatively low cost vs new wells, refracs, gas injection etc.  There are plenty of non-toxic surfactants that will work, from large chemicals manufacturers. Water availability can be a challenge, but the needs are far smaller than for initial completions. 

How much confidence can investors place in type curves or forecasts for shale EOR given limited field history?  Not much at this point.   We have done over 90 wells, and it is very difficult at this point to define any sort of “standard” post stimulation type curve.  This will come along as the technology develops to the point that companies are able to write up reserves because their confidence in the technology is high enough to do so.

What research breakthroughs—experimental, computational, or materials-based—do you believe are most likely to unlock scalable shale EOR over the next decade?   At a high level, we think the area most ripe for breakthrough is actually the “field experiment” area, but we don’t mean the usual “stimulate a zillion wells and then look at statistics” approach.   The leverage is in well thought out lab methods that we can nail down in the lab and extend to the field, enabling optimization from a first principles perspective.