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Fluid contacts identification

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Defining the depths of the fluid contacts, gas/water contact (GWC), oil/water contact (OWC), and gas/oil contact (GOC), or defining both of the latter in some reservoir situations, is essential for volumetrics calculations and important for detailed petrophysical calculations. For example, for more-accurate porosity calculations, the reservoir’s vertical interval needs to be subdivided by fluid type to account for differences in the average fluid saturation and, hence, differences in fluid density or sonic travel time in the various fluid intervals: gas cap, oil column, or aquifer. For the water saturation (Sw) calculations, the depth of the OWC or GWC, or more particularly the related free water level (FWL), is a required input for any Sw calculations using capillary pressure, Pc, data. These depths need to be defined in every wellbore, to the extent that they occur. This article addresses the methods used to make the most accurate determination of the GOC, OWC, and/or GWC depths at the wellbores. This article does not address the larger topic of how these fluid contacts may vary over the whole of the reservoir either because of faults, rock-quality variations, isolated sands, a reservoir’s hydrocarbon-filling history, or hydrodynamics of the reservoir-aquifer system.

Data for calculating fluid-contact depths

There are four types of data that can be used to define the fluid-contact depths in a wellbore:

  • Mud logs
  • Cores (geologists’ descriptions and routine-core-analysis data)
  • Resistivity and neutron logs
  • Formation-tester pressure surveys

These are listed approximately in the order in which these data are gathered from a wellbore. Each has its own strengths and weaknesses. Each is an independent source of information; therefore, the most accurate fluid contact is obtained by using all of the data available for a particular well. The first step in using any and all of these data sources is to align their depths as accurately as possible.

Mud logs

Mud logs record mud gas compositions and quantities and descriptions and analyses of drill cuttings. These provide information about the fluid content and lithology of the rock as it is drilled. These data have some depth uncertainty because of the lag time between a rock interval being drilled and the time the cuttings are recovered at the surface. The field personnel work to minimize this uncertainty by periodically dropping a bit of "carbide" into the drilling mud and then determining how long it takes for it to show up on the mud-returns gas-chromatograph output. The mud log gas-analysis data plotted vs. drilled depth, and adjusted for drilling rate, is a semi-quantitative measure of the gas content over the reservoir interval. It can be used to determine a GWC or OWC because the background gas content per unit volume of aquifer brine is so low compared with that of free gas or gas dissolved in oil. The methane-concentration log is most useful for defining the top of the reservoir and the GWC for a gas reservoir, and the detailed gas analyses can also identify a GOC from increasing ratios of the heavier hydrocarbon components compared with methane as depth increases.

Direct observation of oil staining, and yellow or brown ultraviolet (UV) fluorescence on drill cuttings, identifies oil. When drill cuttings are crushed in solvents, mobile oil migrates to the solvent, which then fluoresces. Gas condensate has a bright white fluorescence. These characteristics assist in identifying oil and gas reservoirs, the top of the reservoir, GOC and OWC, and, possibly, the base of the reservoir.

Water-based-mud cores

WBM cores can provide direct observations of the OWCs and GOCs. Because of differences in the colors of the oil staining, the depths of gas, oil, tar, and relict-oil intervals can often be determined visually from the cores, especially when they are cut at a high rate of penetration. It is common practice to photograph cores in both white and UV light to provide an accessible, permanent visual record. These visual observations are typically complemented by the routine-core-analysis So data over the same depth ranges. [1] Gas and aquifer intervals have low core oil saturations, and tar intervals often have high core oil saturations.

Log-based methods

The use of resistivity-log data is another method of determining OWC and GWC depth in a wellbore. [2] The resistivity logs are used to calculate Sw, and where there is a significant decrease in the Sw values (decreasing from near 100% PV as one moves up through the reservoir interval), that depth is defined as the fluid-contact depth. Also, the invasion profile of the shallow- vs. deeper-reading resistivity tools can be used to help define the depth interval in which the fluid contact occurs. This is true of either WBM- or OBM-drilled wells. Also in WBM-drilled wells, tar intervals can be defined by those depths over which the shallow- and deep-reading resistivity tools show a lack of oil-saturation change, which indicates that the hydrocarbons in the pore space are too viscous to be displaced by the WBM filtrate. If the reservoir is not too shaly, neutron logs can be one of the keys to identifying gas-bearing intervals. [2] A GOC, or a GWC, can be defined at the depth at which the neutron porosity significantly decreases and the density and sonic porosities slightly increase as one moves up through the reservoir interval.

Formation-pressure surveys

The best data from which to determine FWL fluid contacts are given by wireline formation tester tools that measure pressure at discrete depths over reservoir intervals. [3] In going vertically from the gas cap into the oil column, or from the hydrocarbon column into the aquifer, there will be breaks in the formation-pressure vs. depth trends as one moves from a very low gas pressure gradient (0.10 psi/ft or less) to the higher oil pressure gradient (typically 0.25 to 0.35 psi/ft) and then to the water pressure gradient (0.40 to 0.55 psi/ft). When adequate data can be collected, the fluid contacts can be determined very accurately by identifying the depths at which the characteristic pressure gradients change. See the page reservoir pressure and temperature along with associated pages for additional information on fluid-contact depth determination using pressure information.

Overall, the formation-pressure-survey data should be the primary source of data for defining the FWL fluid contacts. The other data should be used to complement these pressure data, or should be used together to define the fluid contacts if no pressure-survey data are available. In reservoirs with sand/shale sequences, sometimes the fluid contact is determined to be within a shale interval, even if that interval is only 10 ft thick or less. If this is the case, the best estimate depth of the fluid contact is at the mid-depth of the shale interval (unless the pressure-survey data indicate otherwise). The fluid contact may be different from the FWL, and it is the FWL depth that is important commercially and important when making Sw calculations from Pc/Sw data.

Since the introduction of 3D-seismic surveys, acoustic-impedance contrasts between gas-, oil- and water-bearing formations are increasingly used. The impedance is dependent on the density and acoustic velocity of each fluid. Many reservoirs exhibit a significant change of acoustic impedance at the fluid contacts, allowing the contacts defined at the wells to be propagated, with data control, into the undrilled areas of the reservoir. These impedance maps show visual "haloes" around a GWC or OWC. These same impedance changes may also be seen in vertical seismic sections and assist in identifying the top of the reservoir, GOC, GWC, and OWC.


  1. Fundamentals of Rock Properties. 2002. Aberdeen: Core Laboratories UK Ltd.
  2. 2.0 2.1 Log Interpretation Principles/Applications. 1989. Houston, Texas: Schlumberger
  3. Formation Multi-Tester (FMT) Principles, Theory and Interpretation. 1987. Houston: Baker Atlas, originally published by Western Atlas.

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See also


Petrophysical data sources

Petrophysical analysis case studies

Fluid identification and characterization

Layer thickness evaluation

Net pay determination