Virtual Petrophysics

VPPS Byte 1: How can I integrate my NMR log data? Or Is it Water or Hydrocarbon?


Common Objectives

Ok.  So now you have acquired an NMR log often regarded as a “specialty” service, and you are wondering how do I integrate this into my petrophysical evaluation. This is not your local service company representative selling his wares, but an experienced user of NMR log data.  Let’s start off with the basic or most often set objectives for running an NMR log.

  1. Bound Fluid Porosity / Irreducible Water Saturation:  From the beginning of time (well maybe the last century) this been the holy grail of logging measurements, a log that can subdivide porosity into the various components, i.e. micro vs macro, or effective vs bound.  Sounds easy, right?  There are assumptions and if someone tells you to go out and calibrate with NMR core measurements, don’t bother.  You can calibrate the T2 cutoff against either Dean Stark water saturation or irreducible water saturation from drainage capillary pressure measurements.
  2. Porosity
  3. Permeability
  4. Fluid ID
  5. Bitumen Detection

Let’s assume that the service company did a reasonable job ensuring you have received good NMR log data, i.e., accurate, repeatable, low noise content.

Getting straight to the bottom line, what will I do with either bound pore water or irreducible  water saturation?  How about an independent check on your computed water saturation.  Some might say, it’s good enough, well I would suggest that having another estimate of water saturation, free of all the assumptions and uncertainties involved with an electrically based water saturation model would be quite important, especially when deciding where to perforate.  Another application is validation of your saturation height function, SHF.

The importance of irreducible water saturation measurements will be shown in this post.

Irreducible Water Saturation

THE DEFINITION: Irreducible water saturation is the minimum water saturation in the reservoir that occurs at the most crestal position, or highest elevation, and is associated with the maximum capillary pressure between the wetting and non-wetting phases (oil and water, gas and water, gas and oil).  It is not, the point where the drainage capillary pressure reaches an asymptote.

Figure 1

Figure 1

As you can see in the Figure 1 example from a hydrocarbon bearing marginal marine reservoir sequence, there is a distinct drop in the resistivity in the middle of the reservoir section that would suggest a water contact, or could it be a lithology effect.  Both the GR and density-neutron separation indicate a fairly uniform porosity and shale content.  The two sharp breaks to lower resistivity in the lower third of the reservoir are caused by very thin layers of conductive diagenetic pyrite.  This pyrite has been confirmed in whole core taken from an offset well.

Now let’s look at the petrophysical evaluation of porosity and water saturation from this set of logs.

Figure 2

Figure 2

The total porosity and bulk volume water are shown in track 5 and water saturation in track 6 of Figure 2.  The water saturation mimics the resistivity response of low water saturation (20 to 40 s.u.) above the contact , but instead of 100 percent water saturation below the contact, the saturation is 40 to 60 percent water.   Is it a residual column from a breached seal, or a structure that has been tilted with an imbibition leg, or a lithology effect?

Now we will introduce two additional saturation estimates: 1) Water saturation from a saturation height function, SHF, and 2) Water saturation from an NMR log.

Figure 3

Figure 3

Figure 3 shows the SHF saturation in track 6 as the red curve, along with the actual height above FWL (HAFWL) in track 1 determined from field pressure data.  The HAFWL starts at approximately 40 metres at the base of the reservoir and reaches 100 metres at the top.  The SHF overlies the original computed resistivity-based water saturation.  This confirms that the electrical properties and environmental corrections used to compute the resistivity water saturation are duplicated in a completely separate independent estimate based on drainage capillary pressure water saturation.

So back to the question, is it water or hydrocarbon or a lithology effect?  Hydrocarbon presence is confirmed at this point by the two independent estimates that agree.  But will it produce water if perforated in the lower section of the reservoir.  The irreducible water saturation from NMR is also presented in track 6, which overlies the other two estimates of water saturation.  This additional piece of information tells us that the entire reservoir is at irreducible water saturation and that no mobile water is present.

Without the NMR measurement, we would have no idea whether the well will produce water-free hydrocarbon even though the SHF and resistivity-based water saturation are in agreement.

This is the most basic use of NMR log data, but an extremely valuable tool in the arsenal of the petrophysicist if used.  Unfortunately, many wells may have this data available, but it is not used or integrated into the standard petrophysical evaluation.

You can make this same presentation by simply plotting the NMR bound fluid volume porosity (BVI, BVF, MBVI) along with your total porosity and bulk volume water (BVW).  After computing irreducible water saturation as the ratio of NMR bound fluid volume to NMR total porosity, plot it alongside your water saturation.

Swirr = BVI/PHIT

NMR Rules of Thumb

  • Swt > Swirr indicates presence of mobile water
  • Swt = Swirr indicates reservoir is at irreducible conditions with no mobile water
  • Swt < Swirr not possible in the subsurface.  Either something is wrong with either the resistivity-based saturation, or the NMR irreducible saturation computations.

In our next VPPS Byte post we will discuss Critical Water Saturation and how it impacts the interpretation of Mobile Water.


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