Surfactants, CMC, Emulsions and Foams

Oilfield Surfactants for Fracturing Fluid and Drilling Fluids: Screen Each Surfactant Additive by Surface Tension and Interfacial Tension to Improve Flowback, Oil Recovery and Well Productivity

Surfactants in frac fluids, drilling fluids and recovery chemicals only help if they still lower surface and interfacial tension in your field brine, at your dose. Measure both by pendant drop across dose and salinity, then send only the best candidates to core floods and field trials.

Who this is for: Oilfield chemical formulators, completion and stimulation engineers, drilling fluid labs and EOR researchers screening surfactant formulations.

Where it fits: Product screening, dose and salinity checks, batch release and supplier comparison, before core floods and field trials.

What it does not do: It does not run at reservoir pressure, measure ultralow interfacial tension or replace core flood and field tests.

Method

Pendant drop surface tension and oil and water interfacial tension; sessile drop contact angle on rock or proxy surfaces

Standard

Optical alternative to ASTM D1331 force tensiometry for screening

Setup

About 2 minutes

Book a 15 minute demo Request a quote

Written by

Abhimanyu Bhandankar

Holds an MBA from Schulich School of Business and a BE in IT. He joined Droplet Lab in July 2019 and now leads sales and marketing.

CEO at Droplet Lab

Why oilfield surfactant screening matters

2 to 26%

of the fracture fluid was recovered during flowback in Marcellus wells in northeastern West Virginia, across 187 wells analysed.

Zhou et al., SPE Production and Operations 31(2), 2016

105° to 32.6°

fall in water contact angle on reservoir rock with a cationic surfactant, against 103.1° with slickwater alone, in a low permeability recovery study.

Li et al., Energies 10(9):1279, 2017

About 1.5 million gallons

median total water volume per hydraulic fracturing disclosure, across 34,675 disclosures from 2011 to 2013.

US EPA, Analysis of FracFocus 1.0 data, 2015

Sources: Zhou Q. et al., Evaluating fracture fluid flowback in Marcellus using data mining technologies, SPE Production and Operations, 2016; Li S. et al., Recovery of low permeability reservoirs considering well shut ins and surfactant additivities, Energies, 2017; US EPA, Analysis of hydraulic fracturing fluid data from the FracFocus Chemical Disclosure Registry 1.0, EPA/601/R-14/003, 2015. Figures come from these sources, not from Droplet Lab measurements.

Quick reference

What this surfactant screen does and what it does not

A quick reference for oilfield chemistry teams checking fit before reading further.

Evidence Box

Problem this solves

Surfactants and flowback aids chosen from supplier data that underperform in high salinity field water or with the field's crude.

Standards

Pendant drop is an optical alternative to ASTM D1331 ring and plate tensiometry for screening. API RP 13B covers field testing of drilling fluids, which this check supports, not replaces.

Peer reviewed method

The Dropometer drop shape method was validated against a KRUSS DSA100E in two peer reviewed papers, in Review of Scientific Instruments and Colloids and Surfaces A.

Customer case study

A University of Waterloo rheology lab added a Droplet Lab pendant drop tensiometer in 2024 and reported surface and interfacial tension in seven publications.

Published research

Waterloo researchers found cationic polymer and anionic surfactant mixtures were markedly more surface active than the surfactant alone (Fluids, 2025).

Honest limit

Room condition readings guide screening. Reservoir temperature, pressure and rock still need core and field tests.

Who this is for

What oilfield surfactant question are you trying to answer?

Pick the card closest to your role. Each one points to the part of this page that answers it.

Oilfield chemical formulator

You develop flowback aids, microemulsions, viscoelastic surfactants or EOR surfactant formulations. Surface tension and interfacial tension curves across dose and salinity rank candidates and show where each formulation stops working.

Test in the field's own brine; salinity and hardness change surfactant behavior.

Completion or stimulation engineer

You choose additives for each fracturing operation, from shale gas to oil wells, and need evidence that a product helps fluid recovery from your shale reservoirs. A quick comparison in your water and with your oil narrows the trial list for each gas well or oil well.

Lower surface tension alone does not prove better flowback; confirm with cores or field data.

Drilling fluid or QC lab

You check incoming surfactant, emulsifier and clay stabilizer batches for drilling mud and completion fluids. Surface tension at a fixed dose gives each batch a recorded release decision.

Set gates from your approved batch, not from a supplier data sheet.

Fit check

Is this the right screen for your oilfield fluids?

It compares how surfactants act at interfaces in your fluids. It does not reproduce downhole conditions.

Good fit if

You compare surfactant products or doses in field brine.

You need oil and water interfacial tension with your crude.

You check how salinity and temperature affect a surfactant.

You release surfactant or additive batches against a reference.

You study polymer and surfactant mixtures, such as friction reducer and surfactant blends.

Less relevant if

You need ultralow interfacial tension for chemical EOR; that needs spinning drop.

You need readings at reservoir pressure.

You need rheology, friction reduction or proppant transport data.

You need dynamic surface tension at millisecond ages.

Summary

How to screen oilfield surfactants

The answer in under a minute.

Mix each surfactant in your field brine at several doses, measure surface tension and oil and water interfacial tension by pendant drop, and plot the curves. Shortlist products that reach low tension at a practical dose and stay stable at field salinity, then confirm the best with core floods or field trials.

The Dropometer pendant drop tensiometer runs both measurements; our surface tension measurement guide and ultimate guide to surfactants explain the methods. A University of Waterloo rheology lab used it for polymer and surfactant mixtures, close to friction reducer and surfactant blends. Our oil and gas guide covers the wider context.

Expert Quote

Expert perspective on surfactant curves

Surface tension versus concentration is one of the few measurements that lets you watch a surfactant reorganise an interface in real time; read the curve, not just the endpoint.

The problem

Why oilfield surfactants underperform in the field

In hydraulic fracturing, or fracking, millions of gallons of hydraulic fracturing fluids are pumped into shale and tight gas reservoirs; EPA's analysis of FracFocus data found a median of about 1.5 million gallons of water per disclosure. Much of that fluid stays in the formation around the hydraulic fractures. In Marcellus wells in West Virginia, only about 2 to 26% of the fracture fluid was recovered during flowback. Water held in tiny pores by capillary forces can block hydrocarbon flow and reduce well productivity. Oilfield surfactants are added as flowback aids, microemulsions, wetting agents and emulsifiers to reduce surface tension, lower interfacial tension against the crude oil and alter rock wettability, so more fluid comes back and oil production and gas production improve. The same chemistry appears in the fluids used to drill, in drilling fluids and drilling mud, in completion and well stimulation fluids, and in chemicals to enhance oil recovery. The difficulty is that a surfactant's data sheet is measured in fresh water at room temperature. Field brines can be very high in salinity, the crude and rock differ from well to well, and friction reducers, clay stabilizers and other additives interact with the surfactant. A product that looks right on paper can fall out of solution, give the wrong interfacial tension or stabilise emulsions. Across the oil and gas industry, teams also want environmentally friendly chemistry with lower environmental impact, which means new types of surfactants with little field history. Teams need a fast bench screen in their own water and oil before committing to core floods and field trials.

Low load recovery or slow flowback after a frac.

A surfactant clouds or drops out in high salinity brine.

Emulsions form with the crude and slow production.

A new supplier's product behaves differently at the same dose.

Drilling mud additives vary from batch to batch.

Troubleshooting

Why a surfactant underperforms and what to check

Why:

High salinity and divalent ions reduce solubility of many anionic surfactants, so they stop working or fall out.

How to detect:

Surface tension at the same dose is higher in field brine than in fresh water, or the fluid turns cloudy.

Corrective action:

Test salt tolerant chemistries, such as nonionic or zwitterionic surfactants, or blends, in the field brine.

Why:

Below the point where the curve flattens, small dose changes give large tension changes. Our experiment on surfactants and surface tension shows the curve.

How to detect:

Surface tension is still falling steeply at the field dose.

Corrective action:

Find where the curve flattens in your brine; our CMC values for common surfactants give a starting point.

Why:

Very low interfacial tension can help mobilise oil but can also stabilise emulsions with some crudes.

How to detect:

Interfacial tension against your crude is very low and the mixture forms a stable emulsion in a bottle test.

Corrective action:

Balance interfacial tension against emulsion tendency; our page on emulsion stability covers the check.

Why:

Friction reducers, gels and other additives bind or compete with surfactants, changing surface activity.

How to detect:

Surface tension of the full fluid differs from the surfactant alone at the same dose.

Corrective action:

Always test the complete fluid with all additives, not the surfactant alone.

Why:

Surfactant adsorbs on clays and rock surfaces, so less remains in the fluid.

How to detect:

Surface tension rises after contact with crushed rock or proppant.

Corrective action:

Measure before and after rock contact, and adjust dose or chemistry.

Why:

Drop age, needle size and density values change pendant drop results. Our guide to reproducible surface tension measurement covers fair comparisons.

How to detect:

Your values disagree with supplier data or another lab.

Corrective action:

Lock the method, check calibration with pure water, and use correct phase densities.

Not sure which surfactant suits your water and oil?

Send your brine, oil and candidates, and we will compare them on a call.

Book a 15 minute demo

Lab records

What an oilfield surfactant screen record contains

Each check produces a record you can file with the product trial or batch. These records can sit beside your core flood and field data in your existing quality records.

Fluid identity

Product, batch, dose, base fluid and every other additive in the mix.

Water and oil

Brine salinity and hardness, oil or condensate source, and both densities.

Method settings

Temperature, drop age, needle size and repeats per point.

Readings

Surface tension and interfacial tension at each dose, with the curve.

Decision

Shortlist, adjust dose or drop, linked to core flood or field results.

Drop images

Automatic edge and baseline detection gives the same reading from the same image, so a reviewer can recheck any result.

Measurements

What to measure in oilfield surfactant screening

Surface tension

Surface tension against dose in field brine

Why it matters: It shows capillary forces that hold water in tight rock, a key factor in flowback.

How to interpret: Compare products at the same dose and brine; thresholds come from your own core or field correlation.

When it is not enough: It does not include the oil phase.

Interfacial tension

Oil and water interfacial tension

Why it matters: It shows how the fluid acts against your crude, for recovery and emulsion risk.

How to interpret: Lower helps mobilise oil; very low values can stabilise emulsions.

When it is not enough: Pendant drop does not reach ultralow values.

Stability

Readings across salinity and temperature

Why it matters: Surfactants that fail at field salinity fail in the well.

How to interpret: Look for products whose curves hold as salinity rises.

When it is not enough: Room temperature readings do not match downhole temperature.

Wetting

Contact angle on rock or proxy surfaces

Why it matters: It shows whether a surfactant alters wettability.

How to interpret: Compare with and without the surfactant on the same surface.

When it is not enough: Rock chips are rough and variable; use repeats.

Validation

Validated measurement approach for oilfield fluids

How the Dropometer itself has been validated, and where fluid researchers have used it.

Peer reviewed method

The Dropometer drop shape method is published in Review of Scientific Instruments and Colloids and Surfaces A. Contact angle was validated against a KRUSS DSA100E, with a published accuracy of 0.35°.

See the validation papers

Customer evidence in fluid rheology

Prof. Rajinder Pal's group at the University of Waterloo studies how polymers, surfactants and particles change the way fluids flow. A paid loan of a Droplet Lab pendant drop tensiometer from June 2024 added surface and interfacial tension to the lab, reported in seven publications from January 2025 to October 2026.

Read the case study

QC Protocol

How to screen surfactants for frac and drilling fluids

Six steps for one field's water and oil. Repeat for each new field or fluid system.

1

Collect field fluids

Use field brine or a matched synthetic brine, and the field's crude or condensate.

2

Check calibration

Measure pure water first; it should read close to 72 mN/m at room temperature.

3

Mix full fluids

Mix each candidate with every other additive at several doses, and note any cloudiness.

4

Measure surface and interfacial tension

Measure by pendant drop at a locked drop age, using correct densities. Our article on pendant drop versus spinning drop explains when to switch methods.

5

Plot and shortlist

Plot tension against dose and shortlist products that reach low tension at a practical dose, to optimize the dose before trials. Our capillary number glossary entry explains why lower tension helps mobilise trapped fluids.

6

Confirm and release

Confirm with core floods or field trials, then use the same check to release batches. Our guide to the best tensiometer for production QC covers batch testing.

We completed our gage R&R study on the unit and it performed very well.

Brandon Barbee

Corporate Quality Engineer, Zeus Industries, Polymer Manufacturing

Download the oilfield surfactant screening SOP

A two page SOP you can adapt for your fluids, with the method lock, dose and salinity plan, gates against your current product, a troubleshooting table and a record sheet.

Surface tension measurement with the Dropometer

Example output

Example flowback aid screen in field brine

Example data only. Your values and gates will differ and must come from your own core or field results.

How to read this screen

Example gates at 1 gpt in field brine: surface tension at or below 30 mN/m and interfacial tension at or below 5 mN/m, with no cloudiness. Product B meets both. Product A works in fresh water but loses activity in the brine. Product D gives the lowest interfacial tension, close to the pendant drop lower limit of about 1 mN/m, but formed a stable emulsion with the crude, so it is held.

Example flowback aid screen

Product	Surface tension in fresh water (mN/m)	Surface tension in brine (mN/m)	Interfacial tension vs oil (mN/m)	Appearance in brine	Result
No surfactant	72.0	73.5	28.0	Clear	Baseline
Product A, anionic	29.5	41.0	9.5	Cloudy	Drop
Product B, nonionic blend	28.0	28.8	3.2	Clear	Shortlist
Product C, microemulsion	27.5	29.5	1.8	Clear	Shortlist
Product D, cationic	31.0	32.0	1.2	Clear, emulsion with oil	Hold

Example data, not customer data. Synthetic brine at 100,000 mg/L TDS, 22 °C; model condensate; pendant drop at 10 s drop age; 1 gpt dose.

Signal order

The order to check signals when a surfactant disappoints

Check these in order. Each one rules out a cause before you look at the next.

1

Calibration and densities

Rules out method errors before comparing products.

2

Stability in brine

Shows whether the product survives field salinity.

3

Surface tension curve

Shows the working dose; our page on CMC assessment covers the curve.

4

Interfacial tension with crude

Shows recovery potential and emulsion risk.

5

Core flood or field data

Confirms the product works in the reservoir.

FAQ

Common questions about oilfield surfactants

Questions oilfield chemists and completion engineers ask about surfactant screening.

They lower surface tension, which reduces the capillary pressure that holds water in tight pores, and they can shift rock wettability. Li and colleagues found a cationic surfactant cut water contact angle on reservoir rock from 105° or more to 32.6°. Alvarez and colleagues found completion fluid surfactants shifted Bakken cores toward water wet. Confirm each product with your own cores.

No. The surfactant that reduces interfacial tension most is not always best. In an experimental study, Li and colleagues found different kinds of surfactants had a similar ability to lower interfacial tension, but very different effects on rock wettability. Very low interfacial tension can also stabilise emulsions with some crudes. Screen interfacial tension, wettability and emulsion tendency together.

For ultralow interfacial tension. A pendant drop detaches from the needle below about 1 mN/m, while spinning drop measures down to about 0.0001 mN/m (Marquez and colleagues, 2021). Use pendant drop for surface tension and most flowback aid screening, and spinning drop for chemical EOR microemulsions. Our article on pendant drop versus spinning drop explains the choice.

Drop shape methods are used at reservoir conditions, for example at 700 psi (Xu and colleagues, 2005) and up to 20 MPa and 100 °C (Abdulelah and colleagues, 2022), but that needs a pressure cell. The Dropometer measures at bench conditions. Use it to screen and rank, and use high pressure tests to confirm the shortlist.

API RP 13B parts 1 and 2 cover field testing of water based and nonaqueous drilling fluids, but they do not specify surface tension or interfacial tension tests. ASTM D1331 covers surface and interfacial tension by ring or plate tensiometry; pendant drop is an optical alternative for screening.

Across the oil industry, high salinity and hardness reduce the solubility of many anionic surfactants, so they cloud, fall out or lose activity. Nonionic, zwitterionic and blended surfactant systems often tolerate salinity better. Always measure in the field's own brine, at the field dose, and note any cloudiness before reading.

They can. Waterloo researchers measured five surfactants in two polymer systems and found surface tension fell and then levelled off with surfactant concentration, with polymer and surfactant interacting. A related study found cationic polymer and anionic surfactant mixtures were markedly more surface active than the surfactant alone. Test the full fluid, not the surfactant alone.

A pendant drop tensiometer with an optical cell for oil and water interfacial tension, plus contact angle for rock or proxy surfaces. The Dropometer does both at the bench. Our guide to the best tensiometer for production QC compares options for batch testing.

Business impact

What changes when you screen oilfield surfactants in the lab

Typical changes in how teams work. Benchmarks are given only where a published source exists.

Before and with lab surfactant screening

Metric	Before Dropometer	With Dropometer	Indicative Benchmark
Product selection	Supplier data sheets in fresh water	Surface and interfacial tension in field brine and oil	No published benchmark; track on your own fields
Flowback aid trials	Field trial on each candidate	Bench screen first, trials on the shortlist	2 to 26% of fracture fluid recovered in Marcellus wells (Zhou et al., 2016)
Wettability	Not measured	Contact angle on rock or proxy surfaces	Rock contact angle 105° to 32.6° with a cationic surfactant (Li et al., 2017)
Batch release	Certificate of analysis	Surface tension at field dose against a reference	No published benchmark; track on your own batches

See the screen on your own fluids

Send your brine, oil and two candidates. We will show the comparison on a call.

Book a 15 minute demo

Estimate saved screening work

Enter your own numbers. The result is an estimate, not a Droplet Lab claim.

Instrument cost ($) Each Dropometer unit is US$5,000; the default models one unit.

Candidate surfactants or doses tested per month

Test cost per candidate ($) Chemicals, brine, oil and core or trial cost for one candidate.

Technician hours per candidate Fluid preparation, surface and interfacial tension and analysis.

Loaded lab rate ($/hr)

Candidates you expect to screen out before core floods (%) No published benchmark. Use your own estimate and start low if unsure.

Result

~0

Candidates saved per month

~0

Monthly savings

~0

Payback period

~0

First year net benefit

Monthly savings = materials saved + technician time saved from reduced iterations.

Limits

What surface tension cannot tell you about a well

Honest limits, so you know when to reach for another test.

It does not run at reservoir pressure or high temperature.

Pendant drop cannot read ultralow interfacial tension; use spinning drop.

Pendant drop starts from about a second of drop age, not milliseconds.

It does not measure rheology, friction reduction or proppant transport.

Wrong phase densities give wrong interfacial tension.

Lab screening does not replace core floods or field trials.

Pendant drop surface and interfacial tension show how a surfactant acts at interfaces in your fluids at the bench. Reservoir conditions, ultralow interfacial tension, rheology, adsorption in place and production response need their own tests.

Book a 15 minute demo Request a quote

How this page was created

Editorial and technical transparency notes for this page.

Transparency Details 4 checklist items

01

Drafting assistance

Drafted with Claude Opus 5.5 (Anthropic) using web search for sources, then edited by the Droplet Lab team.

02

Technical review

Reviewed and edited for technical accuracy by the Droplet Lab Team.

03

Verification steps

Standard identifiers, units, thresholds and key procedural claims are checked against cited sources before publication.

04

Updates

Reviewed every 12 months or when the underlying method changes.

Report a correction

Spotted an issue in this summary? Send a correction request and our team will review it.

Correction Request

We work hard to keep this page accurate and up to date. If you spot an error (wrong revision/year, missing requirement, incorrect interpretation, or broken link), tell us and we'll review it.

Contact us to report a correction

Sources

References

1.

Zhou, Q., Dilmore, R., Kleit, A., Wang, J.Y. Evaluating fracture fluid flowback in Marcellus using data mining technologies. SPE Production and Operations 31(2):133 to 146, 2016. https://doi.org/10.2118/173364-PA

2.

Li, S. et al. Recovery of low permeability reservoirs considering well shut ins and surfactant additivities. Energies 10(9):1279, 2017. https://doi.org/10.3390/en10091279

3.

Alvarez, J.O., Saputra, I.W.R., Schechter, D.S. Potential of improving oil recovery with surfactant additives to completion fluids for the Bakken. Energy and Fuels 31(6):5982 to 5994, 2017. https://doi.org/10.1021/acs.energyfuels.7b00573

4.

Xu, W., Ayirala, S.C., Rao, D.N. Measurement of surfactant induced interfacial interactions at reservoir conditions. SPE Annual Technical Conference and Exhibition, SPE 96021, 2005. https://doi.org/10.2118/96021-MS

5.

Abdulelah, H. et al. Interfacial and wetting properties in shale, methane and water and shale, methane and surfactant systems at geological conditions. Energy and Fuels 36(17):10155 to 10166, 2022. https://doi.org/10.1021/acs.energyfuels.2c01996

6.

Marquez, R., Bullon, J., Forgiarini, A., Salager, J.L. The oscillatory spinning drop technique. Colloids and Interfaces 5(3):42, 2021. https://doi.org/10.3390/colloids5030042

7.

Berry, J.D. et al. Measurement of surface and interfacial tension using pendant drop tensiometry. Journal of Colloid and Interface Science 454:226 to 237, 2015. https://doi.org/10.1016/j.jcis.2015.05.012

8.

US EPA. Analysis of hydraulic fracturing fluid data from the FracFocus Chemical Disclosure Registry 1.0. EPA/601/R-14/003, March 2015. https://19january2021snapshot.epa.gov/sites/static/files/2015-03/documents/fracfocus_analysis_report_and_appendices_final_032015_508.pdf

9.

API RP 13B-1 and 13B-2. Recommended practice for field testing water based and nonaqueous based drilling fluids. See our API RP 13B page. https://dropletlab.com/industry-standards/api-rp-13b/

10.

Lu, Q., Pal, R. Steady shear rheology and surface activity of polymer and surfactant mixtures. Polymers, 2025. See our analysis of this paper. https://dropletlab.com/validation/citations/analysis/steady-shear-rheology-and-surface-activity-of-polymersurfactant-mixtures/

11.

Sun, C.C., Pal, R. Effect of polymer concentration on the rheology and surface activity of cationic polymer and anionic surfactant mixtures. Fluids, 2025. See our analysis of this paper. https://dropletlab.com/validation/citations/analysis/effect-of-polymer-concentration-on-the-rheology-and-surface-activity-of-cationic-polymer-and-anionic-surfactant-mixtures/

12.

Kim, D., Pal, R. Influence of cellulose nanocrystals and surfactants on catastrophic phase inversion and stability of emulsions. Colloids and Interfaces 9:46, 2025. See our analysis of this paper. https://dropletlab.com/validation/citations/analysis/influence-of-cellulose-nanocrystals-and-surfactants-on-catastrophic-phase-inversion-and-stability-of-emulsions/

13.

Chen, X. et al. Contact angle measurement with a smartphone. Review of Scientific Instruments 89(3):035117, 2018. https://pubs.aip.org/aip/rsi/article-abstract/89/3/035117/368179/Contact-angle-measurement-with-a-smartphone

14.

Surface tension measurement with a smartphone using a pendant drop. Colloids and Surfaces A: Physicochemical and Engineering Aspects. https://www.sciencedirect.com/science/article/abs/pii/S0927775717307744

15.

Droplet Lab validation papers

16.

Customer publications that cite the Dropometer

17.

University of Waterloo case study

18.

Cellulose nanocrystals and surfactants analysis

Oilfield Surfactants for Fracturing Fluid and Drilling Fluids: Screen Each Surfactant Additive by Surface Tension and Interfacial Tension to Improve Flowback, Oil Recovery and Well Productivity

Abhimanyu Bhandankar

Droplet Lab Team

Featured Studies & Publications

Why oilfield surfactant screening matters

2 to 26%

105° to 32.6°

About 1.5 million gallons

What this surfactant screen does and what it does not

Evidence Box

What oilfield surfactant question are you trying to answer?

Oilfield chemical formulator

Completion or stimulation engineer

Drilling fluid or QC lab

Is this the right screen for your oilfield fluids?

Good fit if

Less relevant if

How to screen oilfield surfactants

Expert perspective on surfactant curves

Why oilfield surfactants underperform in the field

Why a surfactant underperforms and what to check

Not sure which surfactant suits your water and oil?

What an oilfield surfactant screen record contains

Fluid identity

Water and oil

Method settings

Readings

Decision

Drop images

What to measure in oilfield surfactant screening

Surface tension against dose in field brine

Oil and water interfacial tension

Readings across salinity and temperature

Contact angle on rock or proxy surfaces

Validated measurement approach for oilfield fluids

How to screen surfactants for frac and drilling fluids

Collect field fluids

Check calibration

Mix full fluids

Measure surface and interfacial tension

Plot and shortlist

Confirm and release

Download the oilfield surfactant screening SOP

Example flowback aid screen in field brine

Example flowback aid screen

The order to check signals when a surfactant disappoints

Calibration and densities

Stability in brine

Surface tension curve

Interfacial tension with crude

Core flood or field data

Common questions about oilfield surfactants

What changes when you screen oilfield surfactants in the lab

Before and with lab surfactant screening

See the screen on your own fluids

Estimate saved screening work

Estimate saved surfactant screening work.

What surface tension cannot tell you about a well

Standards, evidence and related surfactant workflows

API RP 13B

ASTM D1331

University of Waterloo

Polymer and surfactant mixtures

Cationic polymer and anionic surfactant

Dropometer

Surfactants, CMC, emulsions and foams

Wettability alteration screening

Foam control and foam quality

Drift reduction adjuvants

How this page was created

Drafting assistance

Technical review

Verification steps

Updates

Report a correction

References