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Direct Hydrocarbon Indicators, or DHIs (also commonly known as, HCIs [HydroCarbon Indicators]), are used every day in the oil and gas industry by technical professionals to help search for hard to find, or simply overseen, hydrocarbon deposits. There are many factors that must be taken into consideration to apply seismic attributes properly; to name a few: 1) understanding rock physics; 2) the signal to noise ratio of the seismic survey; 3) poor processing; 4) insufficient (or erroneous) acquisition parameters, and so on. When gas or oil replace the interstitial brine water in existing reservoirs, the seismic reflection coefficient inherently changes (this is manifested by a difference in the acoustic impedance of the hydrocarbon-bearing zone as compared to the brine-saturated zone either above or below the reservoir in question). This work must be done in order to determine if a well should be drilled OR NOT DRILLED - this cannot be stressed enough; therefore DHI's are a cornerstone application for the hunt of oil and gas deposits. It should be noted that not all seismic anomalies are DHI’d, and not all DHI’s are of equal quality; amplitudes can be caused by factors not related to hydrocarbon accumulations - this is a key point that many geophysicist commonly overlook.
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Basic Concepts of Direct Hydrocarbon Indicators (DHIs)
By: Staffan Kristian Van Dyke1
1 Van Dyke Consulting Services; Houston, TX, USA; email: [email protected]
INTRODUCTION
Direct Hydrocarbon Indicators, or DHIs (also commonly known as, HCIs [HydroCarbon Indicators]), are
used every day in the oil and gas industry by technical professionals to help search for hard to find, or
simply overseen, hydrocarbon deposits. There are many factors that must be taken into consideration
to apply seismic attributes properly; to name a few: 1) understanding rock physics; 2) the signal to noise
ratio of the seismic survey; 3) poor processing; 4) insufficient (or erroneous) acquisition parameters, and
so on.
When gas or oil replace the interstitial brine water in existing reservoirs, the seismic reflection
coefficient inherently changes (this is manifested by a difference in the acoustic impedance of the
hydrocarbon-bearing zone as compared to the brine-saturated zone either above or below the reservoir
in question). This work must be done in order to determine if a well should be drilled OR NOT DRILLED -
this cannot be stressed enough; therefore DHIs are a cornerstone application for the hunt of oil and gas
deposits. It should be noted that not all seismic anomalies are DHIs, and not all DHIs are of equal
quality; amplitudes can be caused by factors not related to hydrocarbon accumulations - this is a key
point that many geophysicists commonly overlook.
Potential Pitfalls in DHI Interpretations
The relative amplitude value can be deteriorated and/or altered dramatically by post-processing of the
seismic data. That is, the numbers associated with the seismic amplitude values are unitless, therefore,
they fall into no particular unit scheme (there is a large misconception in the oil industry that all seismic
amplitudes fit nicely into a -128 to +128 value scheme - THIS IS NOT SO - in fact, they can range
anywhere from -0.00234 to +0.00234 to as high as -14656 to +14656 before processing). Simply put,
amplitude values are unitless numbers - therefore, they are qualitative, not quantitative.
During processing, erroneous artifacts may manifest themselves in the seismic dataset - these need to
be studied with great detail to be certain that they are indeed real or not real; an error of this
magnitude could cost a company $100's of MMUSD, so it is very important to understand what one is
doing and if they are going about it the proper way. Therefore, analog data, calibrated well logs, etc.,
must be used to help determine if these artifacts are true representations of hydrocarbon deposits.
Other major issues include the calibration of wells that are not in the same geologic province because
they come from a different environment of deposition, or the wells used to calibrate the data are simply
too far away from the well being studied. Additionally, if things such as stratigraphic changes (e.g.,
going from a channel fill sandstone environment to a thin bedded levee environment) the well ties and
the prospects will be wildly different. And perhaps the most common error is the lack of sufficient
integration of geological data/interpretations for the prospect being examined.
Basic Seismic Attributes Definitions
DHI or HCI: Measurement which indicates the presence or absence of a hydrocarbon accumulation
(bright spot, dim spot, flat spot, shadow zone, etc.)
Bright spots: Local increase in amplitude on a seismic section (presumably caused by a hydrocarbon
accumulation)
Phase/Polarity Change: Seismic peak changes to a trough (or vice versa)
Dim Spot: Local decrease in reflection amplitude, generally occurs in low porosity sands (10% to 15%)
Figure 01: Flat Spot showing fluid contact of a gas field with an underlying water leg (blue-dashed line)
Figure 02: Gas reflections from the Nile Delta in Egypt; the high amplitude red reflection (trough) is from the top of
the gas in this antiformal trap; conversely, the high amplitude blue reflection is from the base of the gas, or from
the fluid contact.
