Saturation evaluation

The near-wellbore environment is usually altered by the drilling process in several ways, one of which is mud filtrate invasion as a result of overbalance and/or imbibition. The size of the invaded zone depends on many parameters. Some of these parameters are:

• Overbalance magnitude
• Mud-fluid-loss parameters
• Mudcake permeability
• Formation porosity
• Formation permeability
• In-situ fluid viscosity

The exact shape of the invaded zone is unknown but is assumed to be cylindrical. (This cylindrical assumption is not as robust when the borehole encounters dipping beds or is drilled as a deviated hole.)

The radial extent of this invaded zone can be determined with multiple-spaced resistivity tools if the invasion process has altered resistivity, unless the depth of invasion is beyond the zone of investigation of the resistivity tool. If one is comfortable that the shallow-reading resistivity device responds solely from the invaded zone, then one can use the Archie relationship to compute water saturation, as discussed previously. One must take care to determine if the n parameter has changed because the invaded zone is on the imbibition cycle, rather than the drainage cycle usually observed deep within the reservoir. NMR is another method that can be used to determine the invaded zone saturation. Wireline NMR tools do not see deeply into the formation and usually read invaded zone values. The page on NMR logging shows examples of these responses. Generally, filtrate invasion results from the use of either water-based or oil-based mud. Filtrate invasion from water-based mud into the water leg of a reservoir makes no change in S_w. It remains at 100%.

Water-based mud filtrate invasion into the hydrocarbon leg of the reservoir can dramatically decrease the hydrocarbon saturation caused by imbibition, viscous stripping, and gas dissolution. The measured value of fluid saturations in the invaded zone should not be used to predict the residual hydrocarbon saturation by water displacement within the body of the reservoir because the dynamics of displacement are too different.

In the case of oil-based mud filtrate invasion, water saturation will remain immobile if S_w is less than 50% and mild surfactants are used in the mud. There will be no change in oil saturation in the invaded zone when compared with that deeper in the reservoir, unless extreme overbalance is being used. Shallow resistivity logs and NMR logs can be used to determine oil saturation in the invaded zone. These values can then be extrapolated to similar rock types throughout the reservoir.

Introduction

The determination of in-situ oil, gas, and water saturations relies on interpretations of logging devices that read far from the borehole and away from any fluid alterations caused by invasion during drilling. This article provides an overview. A detailed example of calculating water saturation can be found at Water saturation determination

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Tools

The workhorse tools for evaluating saturation are the deep induction and deep laterolog. All other tools such as density, neutron, acoustic, NMR, shallow laterologs, and GR provide readings from the flushed zone that has altered saturations. The most important transform that converts resistivity readings into water saturation is the well-known Archie relationship, which is discussed in resistivity and SP logging. The Archie relationship has many unknowns:

• Porosity (which may have three or four unknowns itself)

• R_w (resistivity of the in-situ water)

• m (an empirical fitting parameter between porosity and resistivity, often called Archie’s cementation exponent)

• n (an empirical fitting parameter between water saturation and resistivity often called Archie’s saturation exponent)

The Archie relationship also has one measured parameter, the formation resistivity, often called the true resistivity. Thus, we have six or seven unknowns and one measurement, which is why a standard is needed (but a standard is rarely available).

In most cases, the saturations in a core have been flushed by the mud filtrate and are not representative of the in-situ reservoir value. Only when we drill with oil-based mud and core high in the oil column where the relative permeability to water is quite low (practically zero) do we recover a core with a value of water saturation at in-situ conditions, after we correct for blowdown from dissolved gas and stress effects on the pore volume of the core sample. The result is an accurate value of in-situ water saturation for zones with less than S_w=50%. Even under these ideal conditions, we have to make empirical corrections to our gold standard. The other case that can be used to calibrate Archie’s relationship is when heavy crude or tar does not move when we core. These cores usually have little or no blowdown because there is little or no dissolved gas. The only correction that is needed is for a stress correction to the pore volume; the result is an accurate value of in-situ oil saturation.

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Calibration

Because the Archie method relies on so many adjustable and often unknown parameters, a calibration step is required to ensure that saturation values are accurate. The method of choice is calibration to a capillary model, which uses multiple core samples for each rock type to provide statistical precision. For a given rock type, several capillary pressure curves are averaged to provide a capillary pressure vs. saturation relation. With some information about the type of hydrocarbon in the reservoir, this relation can be converted into saturation vs. height above the free water level relation. With this model, we can predict, for a given rock type, the hydrocarbon saturation at any elevation in the reservoir and compare it with that computed from the Archie method. Discrepancies between the methods must be resolved by further study, but typically they result in adjustment to one of the many parameters in the Archie method.

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Invaded zone saturation

The near-wellbore environment is usually altered by the drilling process in several ways, one of which is mud filtrate invasion as a result of overbalance and/or imbibition. The size of the invaded zone depends on many parameters. Some of these parameters are:

• Overbalance magnitude
• Mud-fluid-loss parameters
• Mudcake permeability
• Formation porosity
• Formation permeability
• In-situ fluid viscosity

The exact shape of the invaded zone is unknown but is assumed to be cylindrical. (This cylindrical assumption is not as robust when the borehole encounters dipping beds or is drilled as a deviated hole.)

The radial extent of this invaded zone can be determined with multiple-spaced resistivity tools if the invasion process has altered resistivity, unless the depth of invasion is beyond the zone of investigation of the resistivity tool. If one is comfortable that the shallow-reading resistivity device responds solely from the invaded zone, then one can use the Archie relationship to compute water saturation, as discussed previously. One must take care to determine if the n parameter is consistent with the imbibition or drainage cycle controlling fluid distribution in the reservoir. NMR is another method that can be used to determine the invaded zone saturation. Wireline NMR tools do not see deeply into the formation and usually read invaded zone values. The page on NMR logging shows examples of these responses. Generally, filtrate invasion results from the use of either water-based or oil-based mud. Filtrate invasion from water-based mud into the water leg of a reservoir makes no change in S_w. It remains at 100%.

Water-based mud filtrate invasion into the hydrocarbon leg of the reservoir can dramatically decrease the hydrocarbon saturation by imbibition, viscous stripping, and gas dissolution. The fluid saturations in the invaded zone should not be used to predict the residual hydrocarbon saturation by water displacement within the body of the reservoir because the dynamics of displacement are too different.

In the case of oil-based mud filtrate invasion, water saturation will remain immobile if S_w is at sufficiently high capillary pressures as to be considered irreducible and mild surfactants are used in the mud. Shallow resistivity logs and NMR logs can be used to determine oil saturation in the invaded zone. These values can then be extrapolated to similar rock types throughout the reservoir.

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Application of acoustic logs

The potential of acoustic velocity for determination of fluid saturation was recognized soon after development of the first logging devices and quickly became a staple input for log-interpretation methods and software. Acoustic-derived porosity serves as one variable, together with resistivity, in a variety of graphical and empirical methods used for solving the Archie saturation equation. Hingle and Pickett plots are the two most commonly used resistivity-porosity plots. Depending on the data available, the Hingle plot can solve for R_w, Δt_ma, and water saturation (S_w). Pickett plots (Fig. 1) solve for Archie parameters a and m, formation factor, resistivity index, and S_w. A new technique using an empirical equation based on acoustic- and resistivity-log parameters is reported to successfully estimate water saturation in clean and shaly sandstones.

• 

  Fig. 1 – Example of a Pickett plot, including a saturation scaler (courtesy of Baker Atlas).

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Nomenclature

a	=	Archie parameter
C	=	shale compaction coefficient
Cp	=	compaction correction factor
m	=	Archie parameter
v	=	velocity of the formation
α	=	porosity correction factor
Δt	=	transit time, sec
ϕ	=	fractional porosity of rock

References

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Noteworthy papers in OnePetro

Use this section to list papers in OnePetro that a reader who wants to learn more should definitely read

External links

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See also

Petrophysics

Petrophysical data sources

Petrophysical analysis case studies

Acoustic logging

Fluid identification and characterization

Fractional flow evaluation

Layer thickness evaluation

Lithology and rock type determination

Porosity determination

Permeability determination

PEH:Petrophysics

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