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NTG OR N/G: Defining Net Cut-offs 

NTG OR N/G: Defining Net Cut-offs

The Net/Gross ratio is proportion of the GRV formed by the reservoir rock (range is 0 to 1). It is usually defined by a cut off on Permeability or Porosity. It should represent the volume of rock that is able to store hydrocarbons. Sometimes a different definition is used and the NtG represent the volume of rock that is able to produce hydrocarbons. This means the rock that has enough permeability or saturation to produce hydrocarbons. The danger in this method is that recoverability changes through field life and based on the recovery technique and therefore the NtG can change during field life, which can be very confusing. The change in producibility of the reservoir can better be captured in a recovery factor. The table below shows this concept and can help to clear the confusion in what the cut off used for a particular field actually means.


Defining The NTG Cut Off
NtG cut offs seem to come from an era when hydrocarbon accumulations were mainly calculated through map based techniques ether on paper or on simple workstations. With 3D reservoir modeling the need for making a specific NtG property to cut out bad porosity and low HC saturation rock seems a little unnecessary. The low porosity & low Shc cells simple add little extra hydrocarbon volumes. The NtG cut off does aid in reservoir simulation studies as it can significantly speed up run times as low porosity and low permeability cells often lead to numerical issues and long unnecessary run times. On could argue that if a model is only buildt for assessing static volumes a cut off might not be necessary, unfortunately the concept of NtG has been hardwired into the minds of geologist that it is often applied anyway.

The shift, from using NtG mainly for (map-based) volume calculations towards a newer era in which a more dynamic related cut-off (based on permeability or water saturation) is often defined has led to confusion between senior and junior staff. But also today confusion often remains when oil and gas fields move through their development stages and cut-off get redefined by different teams or based on different modeling objectives.

Eventhough the concept of cut offs is often a much debated topic and leads to lively discussion within most integrated reservoir modeling teams a listing of the most industry standard approaches is listed below. Note that the cut-off needs to match the model objectives and therefore we split out modeling for volumetric assessment opposed to dynamic simulation.

Net Rock Cut-off:
For most 3D models one should define the NtG cut off based on the Net Rock properties, usually based on permeability as this defines if hydrocarbons can access the porespace of the rock. This can usually be linked back to porosity though and if necessary defined differently for different facies or fluids. The Net Rock cut off is calibrated in the hydrocarbon bearing zone using the water saturation log, but should be related to a (log) property independent of fluid fill, available for a large number of wells and of which the values are trusted. Usually this is porosity, but sometimes Vshale is also used, or permeability if there are ample cores to calibrate a permeability log to.

There are three industry standard ways of defining the Net Rock cut off.

One can cross plot water saturation versus porosity, Vshale or permeability and identify the value at which the water saturation falls below a certain threshold. This threshold can be defined by looking at analogues, through experience or based on more scientific methods. An example is shown below in which the Sw cut off of 0.8 is translated to a porosity cut off of 0.45 using a regression trend line.


Second, one can look at the Equivalent Hydrocarbon Collumn (EHC) versus cut-off plot and identify below which point only minimal hydrocarbons are cut away. The EHC can be calculated for a range of different cut offs. In the next image the point at which no more hydrocarbons (20 m EHC) are cut away is for the porosities below 0.04. A cut-off above 0.2 leaves no hydrocarbons (0 m EHC) as there is probably no rock with porosities above 20% in this example. Based on this plot the Low case (LC), Base case (BC) and High case (HC) can be defined usually between 90, 95 and 100% EHC, respectively.


When using a Vshale method the same approach can be used, but off course the cut is applied to the values above the Vshale cut off (or below if using a 1-Vshale log). Basically if you would cut out all values with Vshale above 0.18 you would cut out 90% of the EHC. If you would cut out all values above 50% you don’t cut out any EHC anymore. Basically there is no reservoir rock containing both hydrocarbons and more than 50% Vshale.


Third, one can simply use analogue cut off values from nearby fields or from similar reservoirs.

For volumetric consistency the cut off should ideally be applied on logs and upscaled into the model. When applying the cut off on the cells of the model this usually leads to volumetric inconsistencies. In each case the uncertainty needs to be assessed by defining a range of cut offs. This can simply be done per well by comparing EHC values as shown above or by modeling different logs.

Net Reservoir Cut-off
If your 3D model is used for dynamic simulation the geomodeler can help the reservoir engineer by adjusting the cut out those cells that not contribute to fluid flow and can thus be voided to speed up run times. In this case the NtG cut off should be related to the Net Reservoir and calibrated to what cells contribute to flow. Of course the permeability of each cell thus becomes important. Identifying the permeability cut off is thus important and often needs to be related to pressures, fluid types, rel-perms, stimulation techniques, completion strategies and EOR methods.

Even when cut off can be identified, permeability is still a vector and works at different scales and in different directions. A thick cell might require a lower horizontal permeability cut-off than a thin cell as it will have a larger area to allow fluids to flow through. For dynamic simulation the scale of the cells thus becomes very important and can influence the (application of) cut-offs.

A common mistake is to upscale the entire porosity log, apply a permeability function and cut away the cells with a low porosity or permeability that do not contribute to flow. However by doing so, the high perm streaks below cell resolution are lost. For instance, a thin layer with good porosity within poorer sands will be upscaled and averaged away. By applying a poro-perm function the entire cell will now get a lower permeability and might even fall below the perm cut off.

One can better apply the cut offs on the logs and create a NtG log based on this cut off. Then both the NtG, porosity and permeability logs need to be upscaled. All properties can then be modeled and potentially ko-kriged to maintain their spatial relationships. This ensures thin high permeability streaks are still captured, while the NtG of that cell will be very low it’s permeability will be high.

Net Pay Cut-off
A common mistake is to model Net Pay in 3D reservoir models, but this can lead to underestimation of the NtG when the wells that enter the water leg have been used to calculate Net Pay. The Net Pay cut off is usually based on defining a horizontal contact above which the modeling software calculates the GRV.

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