Low resistivity pay zones have baffled many log analysts for years. The causes are usually quite simple but we often have to twist our mindset a little bit.


The most common cause is fine to very fine grained sandstones and siltstones coupled with low resistivity (high salinity) formation water. This kind of reservoir has a naturally high irreducible water saturation, often in the range of 40 to 70%. Lets take a couple of examples:

Assume RW@FT = 0.015 ohm-m.
  Case 1: RESD = 3.0 ohm-m, Vsh = 0.00, PHIe = 0.24
      RWa = (PHIe^2) * RESD = (0.24^2)) * 3.0 = 0.0864
      SWa = (RW@FT / RWa)^0.5  = (0.015 / 0.0864)^0.5 = 0.42
  This is typical of many fine grained sandstone / siltstone reservoirs.

  Case 2: RESD = 4.0 ohm-m, Vsh = 0.00, PHIe = 0.12
      RWa = (PHIe^2) * RESD = (0.12^2) * 4.0 = 0.0576
      SWa = (RW@FT / RWa)^0.5  = (0.015 / 0.0576)^0.5 = 0.51
  This is typical of the Bakken sandstone / siltstone in Saskatchewan.

In these two examples, the logs determines the saturation. Grain size determines that both wells produce clean oil with little water. The same log values in medium or coarse grained rocks would produce water with or without some oil. The numbers are just "answers". It is still up to you to interpret the answers by integrating them with everything else that is known about the rocks. Oil staining, oil on the mud pit, nearby oil production, a production test - all count toward a final understanding of a well's potential.

Many people look at the resistivity value thinking it is below their limits (or their ego) and forget to consider the porosity and water resistivity effects. Once this simple calculation has been done, and production has been proved, the "resistivity cutoff" can be established. But use caution; the cutoff varies with porosity.

Two other situations produce low resistivity pay zones - laminated shaly sands and laminated porosity variations. These are discussed HERE.

Here is an example of a radioactive interval that needs a quick look analysis. If you think like a detective, the answers usually come to light. Gather the evidence, assess the evidence, discard the impossible, select the most probable from what remains. In general, the simplest solution is often the best choice.

We have a zone that is radioactive and looks like a shale on the gamma ray log. The density neutron porosity curves on sandstone scale however show zero separation, so this interval cannot be a shale. This lack of separation is correct foe quartz or feldspar sand. It is radioactive so it can't be quartz, so feldspar it is!

Composite raw data plot for radioactive feldspar sand  

This example has no gamma ray spectral log. It would have been a help, but is not essential since we know the area and the density neutron curves answer all the questions about porosity and lithology.

There is a second issue though, and that is the low resistivity over most of the sand interval. suggesting a water zone. The highest resistivities are in tight anhydrite and dolomite above the sand. The best resistivity in the sand is just 2 to 3 ohm-m in the top 1.5 meters of the sand and the water zone is 0.4 to 0.8 ohm-m, a contrast of about 4:1. An old rule of thumb suggests that a ratio of 3:1 or better means we should complete the well, as long as the porosity is about the same in both the water and oil legs.

A test on the top of the sand in the well on the left, below, produced clean oil, but water cut increased after about six months production. A second well at the right was drilled and tested water with some oil. The resistivity log signature is only very slightly different than the first well. Visually there is not much difference between them.

Detailed petrophysical analysis does show subtle differences. The well on the left shows a 2 meter pay zone on either a long transition zone or a depleted oil zone of about 7 meters. The second well shows only a half meter of pay on top of the same transition zone. The test and production results are confirmed by the fluid distribution in the two wells. And there is not much that can be done to improve the oil production.

Actual saturation (blue curve in Track 3) compared to irreducible water saturation (black curve) in two wells. Where the two curves are close together, little water will be produced at initial completion. Where they are separated, water will flow with the oil. Production histories on these two wells bear out this interpretation: the well on the left produced clean oil for six months, the other tested water with oil immediately.

A good wellsite geologist will correlate his description to the shape of the drilling time log. Later, the sample depths may be adjusted to the open hole logs, especially gamma ray, resistivity, and density logs. In this pair of wells, the first hint of the feldspar sands is in the wellsite sample descriptions as shown below.

Log analysis lithology plot (left) in a complex sequence, and sample description plot (right) over the same interval.
Although the lithology description is not usually quantitative, it is an essential ingredient in choosing the correct mineral mixture for the log analysis lithology calculation. A little care is needed to read these logs. In this case, the word "SAND" describes the rock texture, not its mineralogy. This is a radioactive sand so it must contain feldspar (decomposed granite) and possibly some quartz, as well as the dolomite and anhydrite layers above the sand. Shale, of course must be handled by an appropriate method. In this case, shale cannot be found using the GR inside the radioactive sand interval.

Again we will use our detective skills to sort out the conflicting evidence from the logs shown below. This is a Bakken Sand interval with the Upper and Lower Bakken Shales bounding the sand/silt interval. These shales have very high organic content and are the source rocks for the oil in the Middle Bakken Sandstone. They are also very radioactive, more than 300 API units. This is a clue that uranium may be present as most shales seldom exceed 150 API units.

The sand is also radioactive, averaging 120 API or higher. The potassium, thorium, and uranium curves are in Track 1 with total gamma ray. Uranium content is roughly constant in this example, giving a constant shift to the total GR counts. The thorium curve shows some character but samples and core description indicate clay volume is less than 5%, distributed as burrows and microscopic discontinuous bands.

The density neutron porosity on a sandstone scale is sufficient to indicate dolomite, but the samples suggest a dolomitic quartz sand. Further investigation with XRD shows a 50:50 mix of quartz and dolomite with a few percent pyrite. The pyrite is sufficient to push the neutron porosity a little bit higher and the density porosity a little bit lower, increasing the separation enough to mimic the dolomite effect. Porosity is still halfway between the density and neutron porosity and no shale correction is needed.

The resistivity in the shales is quite high and the sonic, density and neutron all read high, suggesting coaly material. The PE curve disputes this as coal would be less than 1.0 and these shales have a PE of more than 3, representing the mix of clay, silt, and kerogen.

The resistivity in the sand is only 3 or 4 ohm-m, which looks wet. But the very fine grained sand and silt have naturally high irreducible water saturation. This, coupled with a saturated-salt formation water, end up giving a water saturation between 40 and 50%. Clean oil production with small water cut proves the case. Deeper in the basin, the rock becomes more calcitic instead of dolomitic, porosity decreases, resistivity increases, and the zone looks more "normal" but it is still just as radioactive. CAUTION: along the northern edge of this play, water resistivity increases significantly, leading to 15 ohm-m sands that are 100% wet.

But it took 50 years from the first producing well to convince oil company management that this would become the largest oil field in North America. New technology, in the form of horizontal wells and massive hydraulic fracturing jobs, helped turn the mindset around.

Bakken “Tight Oil” example has no kerogen in the productive sand / silt section but very high kerogen content in the shales above and below. Zone is radioactive due to uranium carried from the source rocks during oil migration. Log example showing core porosity (black dots), core oil saturation (red dots). core water saturation (blue dots), and permeability (red dots). Note excellent agreement between log analysis and core data. Separation between red dots and blue water saturation curve indicates significant moveable oil, even though water saturation is relatively high (see text below for explanation). NOTE that the organic rich Upper and Lower Bakken Shales are much more resistive than the Middle Bakken Sand/Silt pay zone due to the high TOC content in the shale. There is no significant kerogen in the sand itself.

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