Wettability Alteration & Tracer Effects on NMR Readings? | Ask PERM

//Wettability Alteration & Tracer Effects on NMR Readings? | Ask PERM

Wettability Alteration & Tracer Effects on NMR Readings? | Ask PERM

Castor from UAE Asks PERM:


We will be drilling & coring with a “KPG (KCL-PHPA-Glycol) Low salinity” fluid, with a pH of 9.5-10.  We will use D20 tracers to assess the core invasion of the fluid.

However, from the literature I have read the following:

  1. “PHPA mud contamination strengthens the wettability of water-wet reservoir rocks”
  2. “Many long chain alcohols exhibit some surfactant properties” – is glycol a long chained alcohol and therefore a surfactant?
  3. “Wettability can be altered if pH of the mud is outside the pH range of 7-8.5”

Have you had any experience with this type of mud and its effect on wettability?  Would you advice against using this type of mud for coring this well? Aside, it seems that D20 has an adverse effect on NMR readings.  Is this correct?




Dr. Jonathan Bryan from PERM Answers:

Hi Castor,

You are correct that there is some literature evidence that these muds can affect reservoir wettability, in particular by helping to disperse polar oil molecules and lift them off rock surfaces.  This would effectively make the reservoir region that is contacted by this mud more water wet.  If you already have a water wet system, then maybe this is okay.  If you suspect that your system is oil wet or fractionally wet, however, then yes you should be cautious about using a possible wettability changing mud and interpreting invasion and residual oil saturation in the swept zone from this data.

You are correct that the D2O has an effect on NMR signals.  D2O contains no hydrogen, so if H2O is swept by invading D2O, the water signal in the swept zone will disappear.  But is this a bad thing?  An option could be to run an NMR log on the well just after drilling, and then flush with the D2O tracer and re-run the NMR log.  The water signal will have mostly disappeared, leaving behind only the signal from your residual oil.  This would allow you understand a couple of things:

1) What is the residual oil saturation (i.e. the oil signal, normalized to the previous signal with both oil and water present).

2) What is the location of this residual oil, compared to the range of T2 values that were present before with water included.  This can also help to assess the wettability of the rock.

As NMR experts, we would be happy to help you with the evaluation of the reservoir wettability.  In general, many of these chemicals are wettability alteration agents.

If you provide more information on the expected wettability (are these water wet or oil wet?) and any other information, we may be able to help.

Best Regards,

Dr. Jonathan Bryan


Castor from UAE Follow Up Question:

Thanks for your prompt response.

Our carbonates tend to be oil-wet at the top and become more water-wet near the OWC.  What I failed to mention was that the core is intended for SCAL experiments, so we would like to use a mud that does not alter the wettability.  Is there a document (or any other source) out there that lists what mud additives alter the wettability, in order to avoid them?

Due to logistics issues, your suggestion on running the NMR twice is not possible.  But, all of these comments are great to consider for future practice.

We are not interested in the evaluation of the reservoir wettability.  But, in the very near future, we would be interested in EOR expertise to help us plan, design and implement an EOR pilot in one of our fields, possibly involving Low Salinity injection.




Dr. Jonathan Bryan from PERM Answers:

Hi Cástor,

Your problems sound very interesting!  We are not too familiar with different drilling muds, to be honest.  That is usually something that the drilling service companies can hopefully help you with?  In terms of operational controls, the one suggestion we have is to try to drill underbalanced if you can, and that will hopefully limit the invasion into the formation.

However, let’s take a minute and think about how you will do the SCAL testing.  I assume you are thinking about things like wettability tests and relative permeability?  You would be looking at end point saturations, etc?  So let’s put aside the possible wettability alteration issue for a second.  If you have some drilling mud invasion, even with no wettability change, you have altered the fluids in your system.  So what many people choose to do is clean the cores, and then re-saturate and age and then run core floods on the re-constituted core.  Was this your plan as well?  Because if so, be aware that cleaning will get all the hydrocarbon off the rock surface anyway.  So if you want to get back to your original wettability state, it is very important to age.  At PERM we always run aging for a minimum of 6 weeks, and in fact we age in the core holder and periodically flush more oil through the core to check that permeability is changing or staying constant with extended aging times.  Not all labs do this, just as a matter of convenience or cost.  But we highly recommend it, if you have the time to age your samples properly.

Note that this method of cleaning core and then aging works on black oil systems.  I didn’t think to ask if you are working with something like a light condensate.  If so, then you will need to be careful that your fluids are representative of the fluids in the formation, etc.  But overall, if you have a system that you are able to age and bring back to the proper wettability, then you maybe don’t need to worry too much about the drilling mud, since you will be re-constituting the samples anyway.

Hopefully this helps.  If you want to discuss more, please feel free to keep going, we enjoy the exchange of ideas.  And yes, we would be more than happy to help you with your EOR plans as well!

Have a great day,



Castor from UAE Follow Up Question:

Hello Jon,

We did look at underbalance drilling.  The problem, however, was the underbalance coring.  It seems that special rigs are needed for this, plus we don’t have the experience on this side of the world.

Yes, the SCAL testing will consist mainly of waterfloods.  For this, the cores will be cleaned with toluene, followed with methanol and then brine.  Then connate water saturation restored by injecting dead oil, and then switching the dead oil for live oil.  Aging is then performed saturating the core for 4 weeks at reservoir conditions, continuously injecting fresh oil through the core.  And then, the core will be re-saturated with fresh live oil.

I believe this is similar to what you have mentioned, and should take care of the wettability concerns at the lab.  My only question is how does the lab know the rock’s initial wettability and saturations; this has yet to be addressed by the lab.

What we are trying to do then is to minimize any wettability alterations that can occur before the cores reach the lab.  So we want to pay special attention to the mud and coring program, as well as the core handling and preservation.

Many thanks for your comments and suggestions.




Dr. Jonathan Bryan from PERM Answers:

Hi Cástor,

Yes, underbalanced coring is very expensive, and even taking the cost of the picture, often there are coring problems, so I personally am not a big fan because it is high risk and often you still don’t know if you can trust the data at the end.

So coming back to your question: the thing to remember is that, when you clean the core, no matter what its initial wetting state is, you remove all fluids.  Then when you bring it back to 100% water saturation, there is more interface so whatever its original wetting preference, now you have rock completely in contact with water.  This is the state that oil comes in.  The good news is that, during original reservoir filling with oil, this was also the state of the rock.  So if something were to make the rock oil wet, it is something to do with the rock and the oil/water in the system.  So the idea is that, with aging, you bring the rock back to its original wetting state.

Now, I should emphasize, that is the goal.  Does it really happen?  Unfortunately, this is something we will never truly know.  I know that, in some oil wet cores we have tested at PERM, we see wettability reverse gradually to an oil wet state during aging.  In others the rock stays water wet, and we will never know if it was actually originally oil wet and cleaning removed the asphaltenes or polar compounds that had made it oil wet over thousands of years.

For this reason, sometimes we have clients that want to take the core state after coring, with no cleaning.  They do the following:

  • On the core, we know that we had some production of fluids (oil and water, volumes unknown) due to depressurization and coring.  So the core at surface contains some void space, and we don’t know exactly what was drained out.
  • We put the core under vacuum to pull air out, if possible.  Then we vacuum saturate with brine.
  • Then we flood with oil and age at this state.

The benefit of doing things this way is that, if there was anything on the rock that altered its initial wetting state, we don’t clean it out.  So that is a big bonus.  But there are two drawbacks:

  • We don’t know the initial fluid saturations, we only know what we put in and what we take out.  So you don’t know actual saturations until the test is all done.  And if something went wrong, like initial saturations didn’t make sense, you don’t know this until you have already spent all the time and money running the core flood.
  • This test gives you the benefit of keeping the initial fluid state, but you don’t get the end point saturations (irreducible water and residual oil) the way you do in a test where you start out water saturated and then flood with oil, etc.

So generally what I recommend to clients is that, if they have concerns about wettability, they run both sets of tests.  We run one set of core floods using the original wetting state of the core.  Then we clean out the system, re-saturate and flood with proper aging times, and look at all the data together to see how representative the second test on the cleaned core is.  If it is representative, i.e. if both sets of kr curves are similar and we get to similar Sorw values in both cases, then we have confidence in the complete displacement test that was run on the second core.

Does this make sense?  Let us know if you want more discussion on this, we are happy to help.

So the other thing I just wanted to mention is that I know you have already selected a lab for testing, and it sounds like things are underway.  Keep contacting us as much as you need, and we will be happy to provide advice like what we are doing now.  But if you find that you need something more involved, the one service that we also offer is that myself and/or our principal (Dr. Apostolos Kantzas) can also act as consultants with you to work with the lab and make sure procedures are correct, and help you with interpretation of lab data afterwards.  So we have this lab, PERM, which can do tests.  But if you wanted to do tests elsewhere, e.g. if it is hard to get samples to us, then the other service we can offer is to work with you as consultants with your other lab, so they would do the tests and we can help you to make sure you get what you need.

But in any case, that wasn’t a sales pitch, I just wanted to make you aware of this, if you felt overwhelmed or if you need assistance.  But please feel free to keep emailing with questions like this as well, that is why we are here and we are always happy to help!

Have a great weekend,






2016-10-25T11:54:49+00:00 April 20th, 2015|Ask PERM (Q&A)|0 Comments

Leave A Comment


Sign up and NOW to receive the latest news, updates and technological advancements made for the Special Core Analysis & Enhanced Oil Recovery Industry

If you don't sign up, you won't know when the next breakthrough occurs!

Sign up for our FREE Newsletter!

We respect your privacy!