RFour Energy · Field Notes

Chemical EOR — and the Chemical Huff & Puff

Q: What is the difference between polymer, surfactant and alkaline flooding?

They attack two different problems. Polymer thickens the injected water to improve the mobility ratio, so the flood sweeps more of the reservoir; it does not reduce the residual oil left behind in the swept rock. Surfactant lowers interfacial tension between oil and water by three to four orders of magnitude, raising the capillary number so that oil trapped in pores can be mobilised; it does nothing for sweep. Alkali reacts with acidic components in the crude to generate soap in situ, which supplements the surfactant and sharply reduces surfactant adsorption on the rock. ASP combines all three.

Q: What is the capillary desaturation curve?

It is a plot of residual oil saturation against capillary number, the ratio of viscous to capillary forces. Below a critical capillary number of roughly ten to the minus five, residual oil does not move at all no matter how hard the flood is pushed. A waterflood typically operates two orders of magnitude below that threshold. To reduce residual oil substantially the capillary number must rise by three to four orders of magnitude, which in practice means lowering interfacial tension rather than raising velocity, because velocity cannot be increased that far.

Q: What is optimal salinity in surfactant flooding?

As salinity increases, a surfactant system passes from a lower-phase microemulsion in equilibrium with excess oil, through a middle-phase microemulsion in equilibrium with both excess oil and excess brine, to an upper-phase microemulsion in equilibrium with excess brine. Optimal salinity is where the oil and water solubilization ratios are equal, and it is where interfacial tension reaches its minimum. Huh's relation, in which interfacial tension is proportional to the inverse square of the solubilization ratio, is what allows an ultralow tension to be inferred from a simple phase-behaviour test.

Q: What is a chemical huff and puff?

A single-well cyclic treatment in which a surfactant solution is injected into the well, the well is shut in to soak, and the well is then produced. Unlike a chemical flood, it does not displace oil from an injector to a producer. It works by spontaneous imbibition: the surfactant alters wettability and lowers interfacial tension so that water is drawn into the oil-bearing matrix by capillary force, expelling oil counter-currently into the fractures. That makes it the practical chemical option in tight and fractured rock where no flood can sweep.

Every chemical method in the catalogue pulls one of exactly two levers: it makes the flood sweep more rock, or it makes the swept rock give up more of its oil. Knowing which lever a chemical pulls is most of the subject.

RFour Energy · Enhanced Oil Recovery Series

After a waterflood, oil is left behind for two separate reasons, and they are not interchangeable. Some of it sits in rock the water never reached — poor sweep, an unfavourable mobility ratio, channelling through the best layers. The rest sits inside the swept rock, trapped in pores by capillary forces the flood could never overcome — the residual oil saturation. Chemical EOR exists because these two failures need two different cures. Polymer thickens the water and fixes sweep. Surfactant destroys the capillary trap and fixes residual saturation. Alkali makes surfactant affordable by generating soap in place and protecting it from the rock. ASP — alkali–surfactant–polymer — runs all three together. And where no flood can travel at all, a chemical huff and puff abandons displacement entirely and lets capillary forces do the work instead.

FIG. 01The whole subject in one diagram. Sweep and residual saturation are independent failures with independent cures. A polymer flood that recovers nothing extra from the rock it sweeps is still working correctly; a surfactant that mobilises oil the flood never reaches is wasted. Confusing the two levers is the commonest error in chemical EOR screening.

Lever One — Polymer and the Mobility Ratio

The mobility ratio M compares how easily the displacing fluid moves to how easily the oil moves. When M exceeds one, the water is more mobile than the oil it is meant to push, and the displacement front is unstable^[4] — water fingers ahead, breaks through early, and thereafter circulates through channels it has already swept. Dissolving a high-molecular-weight polymer in the injected water raises its viscosity, lowers M, stabilises the front and forces water into rock it was previously bypassing.^[2][4]

Two polymer families dominate, and the choice is a water-chemistry decision before it is anything else.

HPAM (partially hydrolysed polyacrylamide) — cheap, efficient, and the workhorse of nearly every large polymer flood. It is also sensitive: viscosity collapses in high salinity and especially in the presence of divalent calcium and magnesium, and the molecule degrades mechanically when sheared hard, which happens at perforations, in chokes and in any pump that treats it roughly.
Xanthan (biopolymer) — markedly more tolerant of salinity and hardness, and far more resistant to shear.^[5] Against that, it costs more and is vulnerable to bacterial attack, so a biocide programme is not optional.

Beyond viscosity, two rock-related effects decide whether a polymer flood is economic. Retention — adsorption on mineral surfaces plus mechanical entrapment — consumes polymer at the front and must be paid for before any of it reaches the oil; clays raise it sharply.^[5] Permeability reduction works in the operator's favour and against it at once: adsorbed polymer lowers the rock's permeability to water more than to oil, which helps conformance but also cuts injectivity, and injectivity is often the binding constraint in the field.

A polymer flood is not a chemistry project with a reservoir attached. It is an injectivity project with a chemistry problem inside it.

Temperature sets the outer limit. Sorbie's practical ceiling for polymer is around 80 °C with an absolute maximum near 95 °C; across 171 reviewed polymer field projects the average reservoir temperature was about 49 °C.^[5][6][1]

Lever Two — Surfactant and the Capillary Number

Residual oil is held in pore throats by capillary forces. Whether the flood can dislodge it depends on the capillary number, the ratio of viscous to capillary force, N_c = vμ/σ. The relationship between that number and how much oil stays behind is the single most important curve in chemical EOR.

FIG. 02The capillary desaturation curve. Below a critical capillary number of order 10⁻⁵, residual oil does not move however hard the flood is pushed — and an ordinary waterflood sits about two orders of magnitude below that. Since velocity is fixed by the pattern and viscosity can be raised only a few fold, the only variable with three to four orders of magnitude of range is interfacial tension. That is why surfactant EOR is chemistry aimed at one number.^[2][3]

Microemulsions and optimal salinity

Reaching an ultralow tension is not a matter of adding more surfactant. It is a matter of putting the surfactant, oil and brine into the right phase state. As salinity rises, the system passes through three classical regimes, named after Winsor, who first classified the phase equilibria of amphiphile–oil–water systems:^[9]

Winsor Type I — low salinity. The surfactant stays in the water and forms an oil-in-water (o/w) microemulsion, the lower phase, in equilibrium with excess oil above it.
Winsor Type III — intermediate salinity. A middle-phase microemulsion forms, in equilibrium with both excess oil above and excess brine below. This is the state that matters: it is where interfacial tension collapses to ultralow values.
Winsor Type II — high salinity. The surfactant moves into the oil and forms a water-in-oil (w/o) microemulsion, the upper phase, in equilibrium with excess brine.

One naming caution, because the literature is not consistent: much petroleum-engineering work labels these II(−), III and II(+) rather than I, III and II, the sign indicating which way the tie lines slope. The same three states are meant. What matters is that the transition is driven by salinity, which is why the whole design problem reduces to finding — and then travelling through — one salinity window.^[7]

FIG. 03A salinity scan. The oil and water solubilization ratios move in opposite directions; where they cross, the system is balanced, the middle phase is largest and interfacial tension is at its minimum. Huh's relation converts that measured ratio into a tension — with σ* = 16.5 it gives about 10⁻³ mN/m, exactly the ultralow value Fig. 02 demands.^[7] Because the optimum is a salinity, formulations are designed with a deliberate salinity gradient so the flood passes through the optimum as it travels.

Alkali, and Why ASP (Alkali–Surfactant–Polymer) Exists

Surfactant alone has an economic problem: the rock eats it. Adsorption onto mineral surfaces removes surfactant from the front, and since surfactant is the expensive component, adsorption often decides the project. Alkali — sodium carbonate or hydroxide — solves two things at once. It reacts with the naphthenic acids in an acidic crude to make soap in situ, supplementing the injected surfactant for almost nothing; and by raising pH it makes sandstone surfaces more negative, which sharply reduces adsorption of anionic surfactant. It can also alter wettability toward water-wet.

Its limits are just as concrete. The crude must actually contain acidic components — a low acid number means little soap. And alkali reacts with the rock: in carbonates, and wherever anhydrite is present, it is consumed rapidly and can precipitate scale, which is a large part of why chemical EOR has been applied far more in sandstones than in carbonates.^[6]

ASP is the assembly: alkali to make soap and protect the surfactant, surfactant to reach ultralow tension, polymer to make sure the resulting bank is swept rather than fingered past. It is the most complete chemical process available, and also the most operationally demanding — three chemicals, each with its own compatibility window, plus scaling and emulsion handling at the producers.

Method	Lever	Mechanism	Principal limits
Polymer	Sweep	Raises water viscosity, lowers M; permeability reduction aids conformance	Salinity & hardness (HPAM), shear degradation, temperature ≈80 °C, retention, injectivity
Surfactant	Residual	Ultralow IFT via middle-phase microemulsion; raises N_c	Adsorption cost, narrow optimal-salinity window, chromatographic separation
Alkali	Residual (assist)	In-situ soap from acidic crude; cuts surfactant adsorption; wettability	Needs acid number; consumption & scale in carbonates/anhydrite
ASP alkali–surfactant–polymer	Both	All of the above together	Complexity, compatibility, scaling and emulsions at surface
Foam	Sweep	Surfactant-stabilised gas mobility control; targets override & channelling	Foam stability with oil, gas supply, modelling difficulty
Gel / conformance^[10]	Sweep	Blocks thief zones and fractures	Placement; blocking the pay as well as the thief
Chemical huff & puff	Residual, near-well	Imbibition & wettability alteration, no displacement	Near-wellbore only, declines per cycle

The Chemical Huff & Puff

Every method above assumes a flood can travel from an injector to a producer. In tight, fractured or unconventional rock that assumption fails outright. The chemical answer is the same architectural move as in gas EOR: give up on displacement and use one well cyclically. Inject a surfactant solution, shut in to soak, produce back.

But the mechanism is completely different from a chemical flood, and this is the part most often stated loosely. Nothing is being pushed. The recovery comes from spontaneous imbibition: the surfactant alters the rock from oil-wet toward water-wet and lowers interfacial tension, so capillary forces — which previously held oil in — begin to draw the aqueous phase into the matrix, expelling oil counter-currently into the fracture network, where it can flow to the well when the well is opened.

FIG. 04Chemical huff and puff is an imbibition process, not a displacement one. Surfactant occupies the fracture network; during the soak, altered wettability and reduced tension let capillary force pull the aqueous phase into the matrix while oil leaves counter-currently through the same faces. The soak is not idle time — it is the process, and its duration is the main design variable.^[8]

Because it is capillary-driven and near-wellbore, the same signature appears as in gas huff and puff: the first cycle is the largest and each subsequent cycle reaches a little further into rock already partly drained, so incremental oil declines. It is not a substitute for a flood where a flood is possible. It is the option that exists where a flood is not.

Documented Field Applications

Daqing — chemical EOR at a scale nothing else matches

Chemical flooding has one reference case so large that it functions as the industry's laboratory. Waterflooding there began in 1960; polymer and ASP flooding began in 1994 and were expanded field-wide. The reported outcome is not a pilot result but an operating statistic: vertical sweep efficiency under polymer flooding ran 29 % higher than under conventional waterflooding, local water cuts fell by up to 30 %, and the incremental recovery attributable to polymer reached about 12 % by 2021.^[11]

The scale is worth stating plainly, because it is what makes those numbers credible. By 2004 polymer flooding was running on 2,427 injectors and 2,916 producers; by 2005 it accounted for a quarter of the field's oil production. Cumulative production from the ASP-flooded blocks had reached 316 MMbo by 2021, with about 20 % of that attributed to ASP itself.^[11]

What the ASP pilots actually returned

The pilot record supports the two-lever argument directly. Five small-scale, single-layer ASP pilots returned incremental recoveries above 20 % OOIP over waterflooding.^[12] The commercial test that followed is the more interesting number: by optimising the formulation and the injection method the team cut surfactant to a third, polymer to two-fifths and alkali to a sixth of the pilot loading — and still recorded 18 % OOIP incremental over waterflood.^[12] Less chemical, nearly the same result, which says the earlier designs were paying for chemical that was not doing work.

And the economics, which chemical EOR discussions often omit: for that ASP programme the chemicals alone cost US$11–15 per incremental barrel, with a total cost of US$15–30 per incremental barrel.^[13] That is the number a project stands or falls on — and it is why the formulation optimisation above mattered more than any further gain in interfacial tension.

The counter-evidence

This is the best case, not the typical one, and the same literature is explicit that some commercial ASP tests failed to meet their objectives.^[13] The failure modes are the ones listed earlier in this article rather than exotic ones: chemical arriving separated rather than together, adsorption higher than the laboratory suggested, and surface facilities meeting emulsions and scale they were never built for. A field with that reservoir quality, water chemistry and three decades of accumulated design experience is not a template that transfers unexamined.

The most useful lesson here is not the 20 % OOIP. It is that cutting the chemical loading by half to two-thirds barely moved the result — which means the earlier design, not the chemistry, was the limiting factor.

Screening and Failure Modes

Published screening for chemical methods clusters around moderate conditions: oil light enough to be mobile but not so light that the target is small, moderate salinity and hardness, permeability high enough to inject viscous fluid, low clay content, and — the sharpest constraint — temperature. Reported guidance places ASP below roughly 93 °C, though the average temperature of actual alkaline-surfactant field projects reviewed was far lower, around 27 °C; polymer projects averaged about 49 °C.^[1][6] Lithology matters too: anionic surfactants adsorb heavily on carbonates and alkali is consumed quickly there, which is why the field record is overwhelmingly sandstone.^[6]

Where projects actually fail is more specific than any screening table:

Adsorption and retention underestimated in the laboratory, so the chemical bank dies before it reaches the oil.
Injectivity — viscous fluid plus permeability reduction, and the wells cannot take the design rate.
Shear and thermal degradation destroying viscosity between the mixing plant and the formation.
Chromatographic separation: alkali, surfactant and polymer travel at different speeds and arrive apart, so the designed synergy never occurs in the rock.
Produced emulsions and scale that the surface facility was never designed to handle — an ASP problem far more often than a reservoir one.
Water quality: divalent ions, oxygen, iron and bacteria each destroy a different component.

Chemical EOR fails in the plant, the wellbore and the first metre of rock far more often than it fails in the reservoir.

Validation

The two-lever framing — mobility ratio and capillary number as the organising principles of EOR — and the fractional-flow and phase-behaviour treatment behind it follow Lake, Johns, Rossen and Pope.^[2] Displacement efficiency, the capillary desaturation curve and the field-scale chemical processes follow Green and Willhite.^[3] Polymer rheology, retention, permeability reduction, degradation and the practical temperature ceiling follow Sorbie.^[5] Microemulsion phase behaviour, the identification of the middle phase and the relation between solubilization ratio and interfacial tension used in Fig. 03 are Huh's.^[7] Screening ranges and the field statistics quoted for temperature come from Taber, Martin and Seright^[1] as compiled and discussed by Sheng, who is also the source for adsorption and alkali-consumption behaviour in carbonates and for the polymer salinity comparison.^[6] Surfactant-driven imbibition as the mechanism of cyclic chemical treatment in tight and fractured rock follows Sheng's later work on unconventional recovery.^[8]

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References

Taber, J.J., Martin, F.D. & Seright, R.S. (1997). EOR Screening Criteria Revisited — Part 1: Introduction to Screening Criteria and Enhanced Recovery Field Projects. SPE Reservoir Engineering 12(3), 189–198; SPE-35385-PA. Part 2: Applications and Impact of Oil Prices, 199–206; SPE-39234-PA.
Lake, L.W., Johns, R.T., Rossen, W.R. & Pope, G.A. (2014). Fundamentals of Enhanced Oil Recovery. Society of Petroleum Engineers, Richardson, 496 pp. ISBN 978-1-61399-328-6. Mobility ratio and capillary number as the two governing principles; fractional flow and phase behaviour.
Green, D.W. & Willhite, G.P. (2018). Enhanced Oil Recovery (2nd ed.). SPE Textbook Series Vol. 6, Society of Petroleum Engineers, 896 pp. ISBN 978-1-61399-494-8. Capillary desaturation, laboratory-scale chemical flooding and field-scale polymer flooding.
Willhite, G.P. (1986). Waterflooding. SPE Textbook Series Vol. 3, Society of Petroleum Engineers. Mobility ratio, sweep efficiency and the baseline against which chemical methods are measured.
Sorbie, K.S. (1991). Polymer-Improved Oil Recovery. Blackie & Son, Glasgow, xii+359 pp. ISBN 0-216-92693-9. Polymer rheology, in-situ viscosity, retention and adsorption, permeability reduction, inaccessible pore volume, degradation and temperature limits.
Sheng, J.J. Modern Chemical Enhanced Oil Recovery: Theory and Practice. Gulf Professional Publishing / Elsevier. ISBN 978-1-85617-745-0. Alkaline, surfactant, polymer and ASP theory with field project statistics; adsorption and alkali consumption in carbonates; HPAM versus xanthan salinity tolerance.
Huh, C. (1979). Interfacial Tensions and Solubilizing Ability of a Microemulsion Phase That Coexists with Oil and Brine. Journal of Colloid and Interface Science 71(2), 408–426. The middle-phase model and the relation IFT ≈ 0.3/(σ*)² used in Fig. 03.
Sheng, J.J. (2019). Enhanced Oil Recovery in Shale and Tight Reservoirs. Gulf Professional Publishing / Elsevier. ISBN 978-0-12-815905-7. Cyclic injection, spontaneous and forced imbibition, and wettability alteration where displacement is impossible.
Winsor, P.A. (1954). Solvent Properties of Amphiphilic Compounds. Butterworths, London. Origin of the Type I / II / III microemulsion classification.
Seright, R.S. — published work on polymer flood design, in-situ rheology and gel conformance treatments, New Mexico Petroleum Recovery Research Center.
C&C Reservoirs, Daqing Complex field-analogue record — a commercial field-analogue database rather than a peer-reviewed source, cited here because it is the compiled operating record: polymer and ASP flooding from 1994, vertical sweep efficiency 29 % above waterflood, local water-cut reductions up to 30 %, incremental recovery of about 12 % by 2021, 2,427 injectors and 2,916 producers by 2004, a quarter of field production by 2005, and 316 MMbo cumulative from ASP-flooded blocks by 2021.
Performance and Effect Analysis of ASP Commercial Flooding in Central Xing2 Area of Daqing Oil Field. SPE-114348-MS, SPE Improved Oil Recovery Conference (2008). Five pilots above 20 % OOIP incremental; the commercial test at 18 % OOIP with surfactant, polymer and alkali loadings cut to 1/3, 2/5 and 1/6 respectively.
Recent Progress and Evaluation of ASP Flooding for EOR in Daqing Oil Field. SPE-127714-MS, SPE EOR Conference at Oil and Gas West Asia (2010). Incremental recovery about 20 % OOIP over waterflood; chemical cost US$11–15 and total cost US$15–30 per incremental barrel; notes that some commercial ASP tests did not meet their objectives.

Frequently Asked Questions

What is the difference between polymer, surfactant and alkaline flooding?

They cure different failures. Polymer thickens the injected water to improve the mobility ratio and sweep more rock — it does not reduce residual oil in the rock it sweeps. Surfactant lowers interfacial tension by three to four orders of magnitude to untrap residual oil — it does nothing for sweep. Alkali reacts with acidic crude to generate soap in situ and sharply reduces surfactant adsorption. ASP — alkali–surfactant–polymer — runs all three.

What is the capillary desaturation curve?

Residual oil saturation plotted against capillary number. Below a critical value of order 10⁻⁵, residual oil will not move however hard you push; a waterflood sits roughly two orders of magnitude below that. Because velocity is fixed by the pattern and viscosity can be raised only a few fold, interfacial tension is the only variable with enough range — hence surfactants.

What is optimal salinity in surfactant flooding?

The salinity at which the oil and water solubilization ratios are equal — the middle-phase microemulsion is largest and interfacial tension is at its minimum. Huh's relation, IFT proportional to the inverse square of the solubilization ratio, lets an ultralow tension be inferred from a simple phase-behaviour test rather than measured directly.

What is a chemical huff and puff?

A single-well cyclic surfactant treatment: inject, shut in to soak, produce. It does not displace oil between wells. It works by spontaneous imbibition — altered wettability and lower tension let capillary force draw water into the matrix and expel oil counter-currently into the fractures — which makes it the practical chemical option in tight and fractured rock.