25th International Meeting on Organic Geochemistry IMOG 2011

O-78
Fluid property prediction from advanced mud gas (AMG)
systems: opportunities and pitfalls
Daniel McKinney 1 , Edward Clarke 2 , E. Esra Inan 1
1 Shell <strong>International</strong> E&P, Inc., Houston, United States of America, 2 Shell <strong>International</strong> E&P B.V., Rijswijk,
Netherlands (corresponding author:daniel.mckinney@shell.com)
Fluid property prediction from mud gas logging has
been a staple of the oil industry for decades (e.g.,
Kandel 1 and references within). However, meaningful
interpretation of these data was long plagued by
inconsistent datasets resulting from poor mud gas
extraction. Recently, a step change was made in the
extraction efficiency of light hydrocarbons in mud
systems with the advent of semi-permeable
membrane technology and heated extractors. These
technologies led to more accurate assessment of the
reservoir fluid composition in, mainly, the C1-C5
range 2 . With these developments, has the ability to
accurately predict fluid properties and phase
behaviour from mud gas data improved?
In this study, insights from petroleum system analysis
and PVT are combined for accurate fluid property
prediction from AMG logging as well as outline
potential pitfalls for misinterpretation of mud gas data.
Petroleum system analysis is a key input because
both oil/source correlation as well as in-reservoir
transformation affect reservoir fluid composition, and,
thus the ability to accurately predict fluid properties
from mud gas data. For instance, oils sourced from
terrigenous material will have significantly different
composition for a given fluid GOR and in situ density
as compared to marine oils with similar properties.
Where local calibration exists, accurate assessment
of fluid properties can be ascertained. For example,
GOR can be easily estimated for an exploration well
in a setting where it has been demonstrated that there
is strong correlation with gas wetness (Wh) (Fig. 1).
Limitations to predictive capabilities can be found,
typically, in mixed petroleum systems or transformed
oil columns. For instance, mixing of dry biogenic gas
with low mature oil can be problematic for AMG
interpretation. Figure 2 shows an example where
there is a strong correlation in a given basin between
the Wh and reservoir fluid in situ density. However,
several outliers exist which have significantly higher in
situ density than what would be predicted from the
Wh value. Upon further inspection, it was understood
that these outliers are due to dilution of a low mature
oil with significant quantities of biogenic gas; a result
not appreciated until methane carbon isotopic data
had been integrated with the results.
In conclusion, great strides have been made to
improve the data quality issues that have hampered
mud gas interpretations in the past. Integration of
these data with basin modelling and petroleum
system analysis can greatly improve predictive
capabilities.
Fig. 1. Fluid property correlation (data in blue) and accurate
prediction (red star) of fluid properties from mud gas data.
Fig. 2. Fluid property correlation to in situ density and
outliers that have been diluted with biogenic gas.
References
[1] Kandel, D., Quagliaroli R., Segalini G., and
Barraud B. (2001) SPE 75307.
[2] McKinney D.E., Flannery M., Elshahawi, H.,
Stankiewicz A., Clarke E., Breviere J. and Sharma S. (2007)
SPE 109861.
140