How To Calculate Net To Gross In Petrel

Use this interactive net-to-gross calculator to estimate reservoir quality from gross interval and net pay inputs, then review a detailed expert guide on how the same logic is applied inside Schlumberger Petrel workflows.

Net-to-Gross Calculator

Expert Guide: How to Calculate Net to Gross in Petrel

Net to gross, often written as NTG or N:G, is one of the most important screening and modeling metrics in subsurface interpretation. In its simplest form, the calculation is straightforward: divide net reservoir thickness by gross interval thickness. Yet in real reservoir studies, especially in Petrel, the challenge is almost never the math. The difficult part is defining what counts as “net,” applying cutoffs consistently, honoring stratigraphy and well data, and carrying the result into maps, property models, and volumetric calculations without introducing hidden bias.

If you are learning how to calculate net to gross in Petrel, the best approach is to separate the workflow into two parts. First, understand the conceptual formula. Second, understand how Petrel stores and computes the data that feed the formula. Once both pieces are clear, your NTG estimates become more reproducible, auditable, and useful for reserve forecasting, static modeling, and development planning.

What net to gross means in reservoir interpretation

Gross thickness is the full vertical thickness of the zone of interest, typically measured between a top and base horizon or within a zonation framework. Net thickness is the portion of that interval that meets your chosen reservoir criteria. Those criteria can include lithology, shale volume, porosity, permeability, water saturation, facies class, or combinations of several cutoffs.

The standard equation is:

Net to Gross = Net Thickness / Gross Thickness
NTG (%) = (Net Thickness / Gross Thickness) × 100

For example, if your gross interval is 75 m and the interval satisfying your net cutoffs is 42 m, then NTG = 42 / 75 = 0.56, or 56%.

How the calculation is typically done in Petrel

Petrel does not change the core formula. What Petrel provides is the framework to derive gross and net thickness from interpreted surfaces, logs, facies, and property models. A common sequence looks like this:

1. Load and quality check wells, logs, checkshots, and deviation surveys.
2. Interpret top and base horizons for the interval of interest.
3. Create zonation so the target interval is clearly defined across wells and surfaces.
4. Apply petrophysical cutoffs to classify each sample or cell as net or non-net.
5. Compute net thickness from logs or model cells within the defined interval.
6. Compute gross thickness as base minus top.
7. Calculate NTG in wells, maps, or 3D grid cells.
8. Validate outputs against geology, depositional style, and production behavior.

That workflow sounds simple, but each step can materially alter the result. A slightly different top pick, a tighter shale cutoff, or a shift from vertical thickness to true stratigraphic thickness can change NTG enough to affect net rock volume and stock tank original hydrocarbons in place.

Step 1: Define the gross interval correctly

In Petrel, gross thickness usually comes from interpreted tops and bases. If your gross interval is not geologically consistent, every NTG result downstream will be questionable. Gross thickness can be calculated from:

• Well tops within a specified zone
• Surface maps generated from interpreted seismic horizons
• Layer thickness in a structural or stratigraphic grid
• Cell thickness inside a 3D geocellular model

You should confirm whether your project requires vertical thickness, true stratigraphic thickness, or model cell thickness. In highly dipping reservoirs, vertical thickness may underestimate or overestimate the geologically meaningful interval. Petrel gives enough flexibility to work in either the well domain or the grid domain, but the team must align on which representation is used for official reporting.

Step 2: Define what counts as net

This is where most interpretation teams diverge. “Net” is not universal. It is a project definition. In one study, net may simply mean clean sand. In another, it may mean clean, porous, hydrocarbon bearing, and permeable rock. Inside Petrel, net can be derived from log cutoffs, electrofacies, interpreted facies, or simulated properties. Typical cutoffs include:

• Vsh less than 0.35 to 0.45
• Porosity greater than 8% to 15%
• Water saturation less than 50% to 70%
• Permeability above an economic threshold
• Facies classified as reservoir facies only

Suppose your team defines net reservoir as Vsh < 0.40 and porosity > 10%. In Petrel, that can be implemented by creating a discrete log or upscaled grid property where each sample or cell gets a value of 1 if it passes all cutoffs and 0 if it does not. Net thickness then becomes the sum of thickness contributions from all intervals with a value of 1.

Step 3: Calculate NTG at the well level

The cleanest place to start is usually the well domain. At each well, determine gross thickness from the top and base picks, then determine the cumulative thickness of intervals passing your net criteria. The formula remains:

NTG at a well = Sum of net interval thicknesses / Total gross thickness of the zone

If a zone extends from 2450 m to 2525 m, the gross thickness is 75 m. If the cumulative clean, porous sand intervals total 42 m, then the well NTG is 0.56. This is the same calculation the calculator above performs.

Within Petrel, well NTG can then be used to:

• Create NTG well logs or zone attributes
• Interpolate NTG maps between wells
• Condition 3D property modeling
• Compare observed NTG with seismic attributes or facies trends

Step 4: Calculate NTG in the grid or 3D model

Once you move from wells to a 3D grid, Petrel usually handles NTG as a cell property or as an upscaled zonal attribute. In a gridded model, each cell has dimensions and can store porosity, facies, saturation, and net flags. There are two common interpretations:

1. Cell based NTG: Each cell stores a fractional NTG value between 0 and 1, representing the fraction of the cell that is net.
2. Zonal NTG: A whole zone or layer package receives an average NTG derived from wells, facies trends, or geostatistical simulation.

Cell based NTG is often more realistic for volumetrics and flow simulation because it captures heterogeneity at model scale. Zonal NTG is simpler and faster for early stage screening. In Petrel, the method selected should match the project maturity and data density.

Cutoffs matter more than the arithmetic

A common mistake is to assume NTG is a fixed physical truth. It is not. It is a measured or modeled fraction under a stated definition. If your porosity cutoff increases from 10% to 12%, net thickness may decrease meaningfully. If your shale volume cutoff relaxes from 0.35 to 0.45, NTG may increase sharply in heterolithic units. Petrel makes these tests easier because alternative properties and scenarios can be stored side by side.

For audit quality interpretation, always document:

• The exact zone boundaries used for gross thickness
• The logs or properties used to define net
• The cutoff values
• The method used for upscaling to the grid
• Whether NTG is vertical, stratigraphic, or cell based
• How missing data and bad hole intervals were handled

Example workflow inside Petrel

A practical net-to-gross workflow in Petrel may look like this:

1. Import LAS files, tops, markers, and deviation surveys.
2. Check depth matching, log quality, and null values.
3. Interpret top reservoir and base reservoir horizons.
4. Create a reservoir zone from those horizons.
5. Generate petrophysical logs such as Vsh, effective porosity, and water saturation.
6. Create a net flag where Vsh < 0.40, PHIE > 0.10, and Sw < 0.60.
7. Calculate cumulative net thickness in each well across the reservoir zone.
8. Calculate gross thickness from base minus top.
9. Compute NTG and visualize it in well tables, logs, and property maps.
10. Populate the 3D model using facies trends, wells, and geostatistical constraints.

Even if your project later introduces more advanced stratigraphic layering or seismic constraints, this foundational sequence remains valid.

Comparison table: what changes NTG the most?

Scenario	Gross Thickness	Net Thickness	NTG	Interpretation Effect
Base case	75 m	42 m	56%	Moderate quality reservoir interval
Tighter porosity cutoff	75 m	36 m	48%	Less rock qualifies as effective reservoir
Relaxed Vsh cutoff	75 m	49 m	65.3%	More mixed sand-shale rock counts as net
Narrower stratigraphic zone	60 m	42 m	70%	Same net rock in a thinner gross interval raises NTG

This table demonstrates why teams should never discuss NTG without also discussing the zone definition and cutoff logic. In practice, many disagreements between geologists, petrophysicists, and reservoir engineers come from definitions, not from calculation errors.

Why NTG matters for reserves and development

NTG directly affects net rock volume, hydrocarbon pore volume, and ultimately economic decisions. A lower NTG reduces the volume of rock expected to contribute to storage and flow. In static models, NTG commonly interacts with gross rock volume, porosity, and saturation according to:

Net Rock Volume = Gross Rock Volume × NTG
Hydrocarbon Pore Volume = Gross Rock Volume × NTG × Porosity × (1 – Water Saturation)

Because NTG multiplies other uncertainty terms, even a modest change can create a large swing in in-place estimates. This is one reason mature subsurface teams perform sensitivity cases on NTG rather than relying on a single deterministic number.

Real-world context from authoritative energy statistics

While NTG itself is field specific and not tabulated globally by regulators, broad energy statistics show why robust reservoir characterization matters. According to the U.S. Energy Information Administration, the United States produced about 12.9 million barrels of crude oil per day in 2023, underscoring the scale at which volumetric assumptions can influence planning and valuation. The U.S. Geological Survey continues to publish technically recoverable resource assessments in major basins, which depend on geologic characterization workflows that include net reservoir concepts. Universities such as Texas A&M and other petroleum engineering programs also teach net pay and NTG as core inputs in volumetrics and static modeling.

Statistic	Value	Source	Why it matters for NTG work
U.S. crude oil production, 2023 average	About 12.9 million barrels per day	U.S. Energy Information Administration	Large scale production decisions depend on accurate reservoir quality models.
Global proved oil reserves, 2020	About 1.73 trillion barrels	U.S. Energy Information Administration international summary	Reserve reporting relies on reliable net reservoir characterization assumptions.
USGS 2018 mean undiscovered recoverable resources in the Wolfcamp-Bone Spring of the Delaware Basin	46.3 billion barrels of oil	U.S. Geological Survey	Resource assessments depend on mapping quality intervals, net rock, and reservoir continuity.

Common mistakes when calculating net to gross in Petrel

• Mixing gross definitions: Using a seismic interval in maps and a different zonation in wells.
• Inconsistent cutoffs: Applying one set of cutoffs in petrophysics and another in modeling.
• Ignoring missing log intervals: Gaps can artificially lower or raise net thickness.
• Confusing net pay and net reservoir: Net pay often includes saturation or mobility criteria that net reservoir does not.
• Poor upscaling: Fine scale net flags can be distorted if upscaling is too aggressive.
• No sensitivity analysis: A single NTG number hides uncertainty.

Best practices for a robust Petrel NTG workflow

1. Start with a written definition of net reservoir and net pay.
2. Use zone boundaries tied to sequence stratigraphy or clear correlation markers.
3. Perform well by well quality checks before any mapping or modeling.
4. Store your cutoffs in named scenarios so the project can be reproduced later.
5. Compare well NTG with facies and depositional environment expectations.
6. Use uncertainty ranges such as P10, P50, and P90 when carrying NTG into volumetrics.
7. Update NTG as new wells, cores, and test data arrive.

How to interpret the calculator above

The calculator on this page uses the core field formula. It computes gross thickness as base depth minus top depth, then divides net thickness by gross thickness. Optional porosity and water saturation inputs provide two extra interpretive measures:

• Net porous thickness: Net thickness multiplied by porosity fraction.
• Hydrocarbon pore fraction indicator: Net porous thickness multiplied by hydrocarbon saturation fraction, where hydrocarbon saturation is 1 minus water saturation.

These extra values do not replace full volumetric calculations in Petrel, but they are useful for screening intervals and checking whether your NTG result is directionally consistent with reservoir quality.

Authoritative references for deeper study

For broader technical and industry context, review these sources:

• U.S. Energy Information Administration: Oil and petroleum products overview
• U.S. Geological Survey: Energy Resources Program
• Texas A&M University: Harold Vance Department of Petroleum Engineering

Final takeaway

If you want to calculate net to gross in Petrel correctly, remember that the equation is easy but the geology is not. Gross thickness must be tied to a coherent interval. Net must be defined with explicit cutoffs. The workflow must be consistent between wells, maps, and 3D grids. When those pieces are aligned, Petrel becomes a powerful environment for generating NTG values that are useful for static modeling, volumetrics, and field development decisions. In practical terms, always document your assumptions, test sensitivities, and make sure every NTG number can be traced back to a geologically defensible definition.