Basic Concepts of Direct Hydrocarbon Indicators (DHIs)

By: Staffan Kristian Van Dyke

Van Dyke Geoscience; Houston, TX, USA; email: staffan.vandyke@vandykegeoscience.com

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 locate hard to find, or simply

overseen, hydrocarbon deposits. A fundamental understanding of basic wave phenomenon, along with

sound geological reasoning, and ideally, the ability to conceptualize these phenomena in 3-dimensions,

is required in order to properly identify DHIs. Determining if suspected DHIs are indeed the oil/gas

response coming from a commercial accumulation of hydrocarbons to that of a seismic relic, could be

the difference between a commercial well and a dryhole. To elaborate more specifically, one needs to:

1) understand basic rock physics [acoustic impedance, reflection coefficients, etc.]; 2) understand the

acquisition survey parameters [shot/receiver spacing, CMP/CDP spacing, fold, etc.]; 3) understand the

survey’s prestack processing workflow [migration, deconvolution, etc.] 4) understand the survey’s

poststack processing workflows [if applicable], and so on.

BASIC SEISMIC CONCEPTS

When gas or oil migrate to replace the interstitial brine water in subsurface reservoirs, the seismic

reflection coefficient inherently changes. The reflection coefficient is most accurately represented by

maxima/minima assignments within the trace envelope by an interpreted seismic horizon. This horizon

is considered to represent a time-equivalent surface, i.e., it is generally interpreted to be a paleo-

depositional bedding plane. The reflection coefficient value is calculated by measuring the difference in

acoustic impedance of the hydrocarbon-bearing zone as compared to the brine-saturated zone, either

above or below the reservoir being analyzed. Put more easily, there are two significant reflection

coefficients to any reservoir – its top and its base.

Another consideration is that the relative amplitude value can be deteriorated and/or altered

dramatically by post-processing of the seismic data (mean/median filters, spectral whitening, etc.). 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 -128 to +128 unit boundaries). This is not so. In fact, the unit samples can range anywhere

from + (1.0 x 10-6 / 1.0 x 106) to - (1.0 x 10-6 / 1.0 x 106) before processing. As amplitude values are

unitless numbers, by definition they are qualitative, not quantitative.

POTENTIAL PITFALLS IN DHI INTERPRETATIONS

During processing, erroneous artifacts may manifest themselves in the seismic dataset. These need to

be studied with great detail to be certain they are indeed real or not real; an error of this magnitude

could cost a company $100's of MMUSD. Therefore, it is fundamental to understand the physical

concepts behind Direct Hydrocarbon Indicators, as well as very important to apply the proper reasoning

while evaluating them. Outcrop/subsurface analog data, calibrated well logs, the creation of synthetic

seismograms, among many other valuable quality control measures, all must be used to help determine

if the suspected DHIs are true representations of commercial accumulations of hydrocarbons.

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.

It should also 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. This work must be done in order to determine if a well should

be drilled - OR NOT DRILLED - this cannot be stressed enough. Clearly, DHIs are a cornerstone

application for the hunt of oil and gas deposits.

DHI DEFINITIONS AND EXAMPLES

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

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 reservoir in this antiformal trap, as the high amplitude blue reflection is from the base of the gas reservoir,

also known as the GWC (Gas Water Contact).