Polymer flood injectivity decline is usually two problems at once: residual polymer left in the formation and injection system, and damage at the rock face that the fluid has to pass through. Where the polymer is the dominant cause, a non-oxidising degradation agent that breaks the polymer backbone can restore injectivity without the oxidative damage that iron and steel in the injection string will suffer from. The useful question is which of the two causes is doing the work.
This note is written for reservoir engineers and production chemists running a polymer flood that is no longer taking injection, and for buyers comparing chemical treatments without knowing which failure they are buying against.
Product referenced in this article
Non-oxidizing Polymer Degrader for Oilfield Polymer Floods — application notes, specification table and document downloads for this range.
What an injectivity decline is actually telling you
A polymer flood puts a large mass of high-molecular-weight polymer into an injection well, normally to hold the water back so that oil sweeps ahead of it. For a long while the well takes injection at a stable rate. Then the rate falls at the same pressure, or the pressure has to be raised to hold the rate. That is an injectivity decline, read from the Hall plot and the injectivity index.
Both describe what has happened at the formation face. Neither explains it. Two entirely different mechanisms produce the same curve, and a treatment aimed at the wrong one will look like a failed treatment.
Why the polymer stays in the formation
Most of the polymer that goes in does not come back, and the remainder is held in the rock by several mechanisms at once. Adsorption is the first: hydrolysed polyacrylamide carries amide groups that hydrogen-bond to the silanol surfaces of clay minerals, and the amount held this way rises with the clay content of the formation. Entrapment is the second — a polymer molecule larger than the pore throat cannot pass, and it is filtered out at the face. Gelation is the third, and it is the one most often missed: calcium and magnesium in the injection brine bridge the charged polymer chains together, and the resulting gel blocks the pore with a plug that behaves like a solid.
Two kinds of damage, and only one of them is chemical
Alongside the polymer there is usually a second mechanism, and it needs a different answer. Fines mobilised from the formation face, sand carried in from the wellbore, and drilling or completion fluid that invaded the near-wellbore zone all restrict flow, and none of them responds to a polymer treatment. Scale and chemical incompatibility between the polymer and the injected brine are further possibilities.
Separating them takes data rather than interpretation. The produced water is tested for polymer content, which shows roughly how much is being left behind. A step-rate test separates the skin from the matrix damage, which tells you whether the restriction is at the face or deeper in the formation. The injection brine is analysed for divalents, because a brine that gels the polymer is itself a reason to change the water treatment.
What an oxidising degrader costs you
The obvious treatment is oxidation. Persulphate, peroxide and hypochlorite will break a polymer chain quickly, and on paper they are cheap. The difficulty is that they are not selective: they attack the polymer and everything else near them.
Radical chemistry oxidises the iron and steel in the injection string, the tubing and the casing, and the iron oxide it produces is a fine, high-capacity plugging solid that ends up in the formation as a new damage mechanism. It also oxidises the other additives in the injection water, and it generates sulphate and chloride in the produced stream. And it has to be near-neutralised before it reaches the rock, because at low pH it attacks the formation itself.
What a non-oxidising route does instead
The alternative is to hydrolyse the polymer rather than oxidise it. Enzymatic degradation agents cleave the acrylamide backbone of the polymer directly, and the fragments that result are short and water-soluble rather than a high-molecular-weight plugging polymer. That difference in what is left behind is the whole argument: there are no radicals, so there is no oxidation of the steel and no iron oxide precipitate, and the polymer can be produced back out instead of staying in the pore space.
The constraint is equally clear. This is a treatment of the polymer, and it does not repair mechanical damage. It also needs contact: the agent has to reach the polymer, in the formation, at temperature and pH where the reaction proceeds.
The dosing decision, and why no number is published
The dose follows from the polymer in the system rather than from the volume of formation. It depends on the polymer concentration and molecular weight being injected, the mass already retained, the temperature at the injection face, the pH and the salinity, and the calcium and magnesium in contact with the polymer.
There is a trade between concentration and contact time that no data sheet can flatten. A concentrated treatment given briefly is not equivalent to a dilute treatment given over days, and pushing either one beyond the limit the polymer chemistry allows gives no further degradation while leaving more chemical in the formation. This is why we return a concentration and a contact time together.
Screening: five questions that decide it
Five questions separate the wells a degrader helps from the wells where a degrader is the wrong purchase, and all five can be answered from data you already hold.
| Question | Towards a degrader | Look elsewhere |
|---|---|---|
| Is polymer confirmed in the produced water and in the injection system? | Yes, and polymer is still being injected | No polymer in the stream at all |
| Does the brine gel or precipitate with the polymer? | Divalents present and polymer gelling | Clean brine, no incompatibility |
| Is the restriction at the face or in the matrix? | Mostly at the face, skin-dominated | Deep matrix damage from fines or invasion |
| Is the injection string iron-based? | Yes, and oxidising damage is unacceptable | No oxidiser concern on this asset |
| Is the temperature at the injection face workable? | Within the operating range of the agent | Too hot for a non-oxidising route |
Where our products sit
Our non-oxidizing polymer degrader for oilfield polymer floods is the product for this application, formulated for PAM and HPAM systems where residual polymer is restricting injection and the injection string cannot take oxidative damage. Where the problem is deposit or near-wellbore cleanup rather than retained polymer, our bio-based oilfield additive is the product to look at instead.
What we do not promise
We do not quote a percentage of injectivity recovered, because the number depends on how much polymer is retained, how it is held, what the brine is doing, and what the mechanical damage has already cost you.
We do not claim that a chemical treatment repairs mobilised fines or a damaged completion, and we will say so in writing if the well data points that way. Nor do we claim that a non-oxidising agent is always the better route: if the system has no oxidisable iron, no other additives and no scale concern, an oxidative treatment may still be more practical.
How to judge whether it is working
Watch the injectivity index and the Hall plot first, and the produced water polymer content second. A treatment that is removing polymer shows up as a falling polymer content in the produced stream before the pressure record changes, because the polymer has to be produced before the injection side feels the difference. That lag is normal, and the trial should not be judged in the first week.
Keep the baseline. A treated period compared against an untreated period compares two reservoir states, not two treatments. And watch the produced water chemistry: if sulphate or chloride rises unexpectedly, something other than the planned treatment is in the system.
Planning the next cycle
Most of this note is about recovering a flood that is already running. The cheaper fix is not to build the decline into the next one. Our guide to biosurfactants for heavy oil viscosity reduction covers where a polymer is retained on the rock and where it is sheared apart on the way in, and our note on deciding whether bio-based oilfield additives fit your reservoir sets out the wider screening. Where mobility control is needed in a saline reservoir, a microbial thickener such as our HL biopolymer is worth looking at in the design stage.
What to send us for a screening opinion
Send the polymer type, concentration and molecular weight used in the flood, the injection rate and pressure history, the injection and produced water analyses with calcium, magnesium and total dissolved solids, the temperature and pH at the injection face, and any step-rate or pressure transient data you already have. Our technical team replies with a screening view: which of the two mechanisms is dominant, and what concentration, contact time and monitoring plan the case calls for. 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.
Frequently asked questions
- What causes polymer flood injectivity decline?
- Usually two things at once. The first is residual polymer: part of the injected polymer stays in the formation, adsorbed on clay surfaces, trapped at pore throats, or gelled by the calcium and magnesium in the injection brine. The second is formation damage at the injection face, mechanical or chemical. The pressure record alone does not separate them.
- Why not simply use an oxidising polymer degrader?
- Oxidising agents such as persulphate, peroxide and hypochlorite do break polymer down quickly, but the radicals are not selective. They oxidise iron and steel in the injection string, and the iron oxide they produce is itself a plugging solid in the formation. They also oxidise other additives in the injection water and generate sulphate and chloride.
- How much non-oxidising polymer degrader does a treatment need?
- We do not publish a single concentration, because the dose depends on the polymer concentration and molecular weight in the system, the mass retained in the formation, the temperature at the injection face, the pH and salinity of the brine, and the contact time. Concentration and contact time trade against each other. Send the water analysis and the injection data and we will return a starting point.
- Can the injectivity decline be reversed completely?
- The polymer component can be substantially removed, because breaking the polymer backbone turns a high-molecular-weight plugging polymer into short, water-soluble material that can be produced back out of the formation. Mechanical damage is a different matter: mobilised fines or invasion from drilling may only partly respond to a chemical treatment.
- What data do you need before quoting a polymer flood cleanup?
- Five items, and with them our application engineers can return a specific recommendation rather than a general description: the polymer type, concentration and molecular weight used in the flood, the injection rate and pressure history, the injection and produced water analyses including calcium, magnesium and total dissolved solids, the temperature and pH at the injection face, and any step-rate or pressure transient test data. We are a National High-Tech Enterprise with 10+ granted patents.