OCTOBER 2014
Technological Innovations
Drive Trends In Onshore,
Offshore Seismic Acquisition
The “Better Business” Publication Serving the Exploration / Drilling / Production Industry
By Scott Singleton, John Gillooly,
Dave Ridyard and Brian Horn
HOUSTON–Over the past decade, the upstream industry has observed the rapid
evolution of advanced seismic acquisition. Sometimes referred to as “specialized”
acquisition, these customized solutions not only have
become immensely valuable and reliable workflow tools,
but also are cost effective and relatively easy to
incorporate into development and production schemes.
Collaboration among various oil and gas experts,
geophysicists, geologists, and petroleum and reservoir
evaluation engineers continues to advance at a rapid pace.
This drives the need for integrated solutions while
accelerating the deployment of innnovative seismic
acquisition tools, with the all-important objectives of
improving well performance and ultimate recovery rates.
Reproduced for ION Geophysical with permission from The American Oil & Gas Reporter
www.aogr.com
SpecialReport: Oil & Gas Computing
Innovation in the realm of seismic acquisition extends the full
gamut, from vast 2-D basin scales to regionally targeted 3-D and
reservoir scales, all the way down to microseismic. Whether land,
offshore or seabed, seismic acquisition continues to evolve in direct correlation to both emerging technology and collaborative
requirements. And this evolution has made great strides in reducing uncertainty while enhancing accuracy and visibility.
Historically, 2-D seismic data have been used to identify structural and stratigraphic leads in emerging and frontier basins. Typically, these surveys are laid out as orthogonal grids, but often are
limited to specific parts of a basin where prospectivity is perceived
to be greatest. In recent years, a renewed appreciation for regional 2-D seismic data has led to the development of basin-scale exploration surveys designed to allow oil and gas companies to evaluate entire basins or continental margins.
Basinwide 2-D surveys are designed to address key exploration
questions and help identify potential petroleum systems and plays.
Basin-scale 2-D surveys can be custom designed to provide critical insights into the geologic evolution, deep-basin architecture,
and depositional and structural history of a specific petroleum system and region. The data are depth-imaged using advanced geological and geophysical processing tools and techniques, with
particular attention paid to imaging key wells, fields and well discoveries to provide an accurate framework for integrating ties with
legacy 2-D and 3-D datasets.
Understanding how exploration plays (whether in a frontier
or mature basin) are identified and pursued across single or multiple basins requires a regional perspective of multiple play types
and how they correlate to the basin’s evolution. This is critical
to creating a diverse and successful exploration portfolio.
Basinwide 2-D projects cover larger areas than traditional 2D and 3-D datasets, which allows correlations between mature
areas, frontier basins, and even conjugate margins that at one time
were part of the same basin and now are separated by an ocean.
Imaging and understanding the present day and reconstructed basin geometries help geoscientists understand rifting mech-
From 2-D surveys covering entire basins, to regionally targeted 3D projects on the reservoir scale, to microseismic analysis focused
on the near-wellbore area, geophysics continues to evolve to reduce uncertainty and enhance accuracy. In this image from the
Marcellus Shale, red bubbles denote 180-day initial production
from a series of lateral well pads. High initial production correlates
with low anisotropy (length of green vectors) because of multiple
orthogonal sets of fractures (J1 and J2 are the two dominant regional joint sets across the Marcellus). The white background indicates areas with slow Vfast velocities, which occur in the presence of multiple fracture directions. Black background areas have
high Vfast velocities and high anisotropy, indicating horizontal
transverse isotropic fracturing with a single set of fractures.
anisms, depositional history in basins, and the conjugate margin.
This is a powerful exploration tool that has provided insights that
led to extending presalt discoveries from Brazil to West Africa.
Broader Perspective
The first state-of-the-art basinwide 2-D project was acquired
in 2002 in the Gulf of Mexico. The idea of acquiring new 2-D
data in an area covered with 3-D seismic and abundant well control may have seemed archaic at the time, yet operators confirmed
the need for a dataset that had a broader perspective and could
assimilate the large volume of information into a consistent and
calibrated interpretation.
The interconnected dataset links the entire Gulf, from the onshore to the deepwater offshore, and from Florida to Mexico, for
a true continental-scale view of the most unique basin in the world.
By doing so, the 2-D imaging provides a comprehensive framework for understanding Gulf geology, and improves operators’
ability to document marginal development, perform crustal reconstructions, and convey the sedimentary filling history of the
entire petroleum region.
The basinwide 2-D program continues to offer new insights
into old Gulf plays, and to provide the context for identifying new
plays as well as extending existing exploration plays south into
Mexico. The ability to construct geologic models connecting prolific regions in the north to opportunities in the south makes constructing basin-scale geologic frameworks ever-more important.
Since introducing basinwide technology in the Gulf, high-quality 2-D data have been acquired in most of the major offshore
basins in the world, providing operators with critical new geophysical and geological perspectives. This can be especially valuable in exploring frontier basins.
A case in point is East Africa, where the regional exploration
history over the past seven years provides an example of how
basin-scale thinking can transform failures into triumphs.
In 2007, the Pomboo No. 1 dry well offshore Kenya encountered wet sands with no shows, and appeared to all but condemn
this margin. However, a careful examination of deep-imaged regional seismic data suggested that the Pomboo structure had limited fetch area from the hydrocarbon kitchen, and therefore was
insufficiently charged (Figure 1).
Correlating these strata to the south and east revealed key strata correlations that indicated there was potential in Mozambique
and Tanzania. Subsequent drilling campaigns in the Ruvuma Basin
in Tanzania and Mozambique have discovered more than 200 trillion cubic feet of natural gas. The data further reveal a possible
oil window farther east, offshore Comoros.
What has become apparent from analyzing basinwide 2-D is
the importance of the correlation and tie between onshore and offshore areas. Given the complexity and cost of land acquisition,
these programs have been slow to develop. However, basinwide
2-D programs in the U.S. Gulf, West Africa, and onshore
Poland have demonstrated the value of tying mature areas to
emerging areas through new acquisition or reprocessing of legacy data.
Regional 3-D Surveys
Industry practice has been to acquire successively more dense
2-D grids of data, while often acquiring 3-D seismic only over
relatively small areas to determine drilling locations on specific prospects. The Gulf of Mexico’s multiclient data boom in the
1990s started a growing trend toward more regional 3-D surveys
SpecialReport: Oil & Gas Computing
to bring the power of true 3-D interpretation to an earlier stage
of the exploration process.
One example is the South Porcupine Basin offshore Ireland.
South Porcupine was identified originally in a basinwide 2-D program, leading to the acquisition of new, multiclient, regional 3D data over the basin–the largest multiclient 3-D seismic survey
ever acquired offshore Ireland. The regional geologic framework
available from the 2-D data made possible not only identifying
the prospective frontier area, but also developing a consistent and
geologically constrained velocity model to deliver enhanced seismic imaging.
Three-dimensional technology continues to evolve rapidly.
Wide-azimuth survey designs and enhanced imaging technologies such as reverse time migration permit imaging below complex salt bodies. In the towed-streamer marine world, broadband
acquisition and processing techniques are allowing the recovery
of higher-frequency data, yielding greater resolution than geoscientists could have imagined 10 years ago. These broadband
techniques also generate a secondary advantage by allowing seismic service contractors to run streamers deeper, thereby reducing noise and weather downtime.
In the land and seabed world, wide-azimuth multicomponent
data acquisition and processing are increasingly delivering
reservoir-scale information that goes far beyond acoustic impedance to define rock properties and fracture information.
Multicomponent Technology
The prevailing standard for seismic acquisition in unconventional plays involves full-azimuth bin coverage, followed by applying rigorous velocity corrections of each azimuth in order to
remove the effects of horizontal transverse isotropic (HTI)
anisotropy. This is enabled by using a novel binning technique
known as offset vector tiles (OVT).
This methodology recognizes that not only does full-azimuth
seismic data have an offset component, but they also have an azimuthal component that must be processed independently so that
amplitude-variation-with-offset and anisotropic effects are measured and corrected for during processing, and can be quantified
in the quantitative interpretation analysis stage.
Over the past decade, multicomponent technology has start-
ed to gain considerable traction because of the proliferation of
high-sensitivity, three-component phones for land and four-component phones for marine ocean-bottom cable acquisition. This
allows converted (PS) waves (known as C-waves) to be recorded as well as standard compressional (PP) waves.
Coincident with multicomponent acquisition technology, the
industry has witnessed a resurgence in C-wave processing techniques, leading to algorithms and workflows tailored specifically to C-waves, including HTI anisotropy removal.
Today’s most advanced 3-D seismic workflows are designed
to incorporate leading-edge multicomponent survey design, acquisition, processing, and analysis for the express purpose of defining the rock and fracture properties of an unconventional
prospect.
In the processing sequence, vertical transverse isotropic
anisotropy (primarily from layering effects) is removed in the OVT
migration stage. This is followed by HTI anisotropy calculation
utilizing elliptical velocity inversion of both PP and PS data, using powerful, full-azimuth/nonsectored surface-fitting velocity
analysis, and splitting estimation and compensation algorithms,
respectively.
The results of HTI anisotropy calculation are used to kinematically remove the effects of anisotropy on the azimuthal gathers,
thereby flattening them. They also are used quantitatively to assess the magnitude and azimuth of fracturing and/or local and regional stress in the project area.
Since it is becoming widely acknowledged that the presence
or absence of natural fractures–and by extension, the ability to
exploit these natural fractures as well as generate new fractures–is
one of the single greatest determinants of successfully exploiting an unconventional reservoir, it is apparent that fracture characterization is an extremely important aspect of reservoir characterization.
Rock properties also are a key to reservoir description. In unconventional reservoirs, the most important properties to be estimated are porosity, clay content and total organic carbon content. Along with these properties, completion programs depend
on evaluating rock toughness, otherwise known as brittleness.
These characteristics are quantified by geomechanical values derived using Young’s Modulus and Poisson’s Ratio. The
FIGURE 1
Regional Structure Offshore Mozambique and Tanzania from 2-D Dataset
FIGURE 2
Shear Stress from 3-D Seismic Data
In Marcellus Shale Prospect
dynamic version of these properties can be calculated using geophysical impedance inversion through acoustic impedance, shear
impedance and density, although there is much debate about the
accuracy of these estimations through seismic inversion. Increased accuracy can be achieved by combining PP and PS data
in a joint inversion, and by including anisotropy in the calculations.
Figure 2 shows shear stress from seismic data in a Marcellus
Shale prospect with considerable structural relief on the east and
north (left and top) caused by the proximity of the Allegheny
Thrust Belt. Knowledge of the stress profile within the prospect
is critical to successfully completing lateral wells. Analysis showed
that an anticline in the lower center of the survey contained a lowstress profile (blue colors and short azimuth vectors in black), making it an optimal location for placing laterals.
Microseismic Monitoring
Microseismic monitoring of hydraulic fracturing operations
has proven particularly valuable in locating and attempting to characterize the very small-magnitude events generated during the fracturing process in unconventional resources plays, where effective stimulation is critical to well performance. Microseismic characteristics include depth of target, rock type, and physical size
of the slip surface (all of which indicate that signal-to-noise ratio remains a huge issue).
With microseismic monitoring, geoscientists are trying, at a
minimum, to determine fracture height, width, azimuth, and some
estimate of stimulated rock volume. They also are interested in
the local geology of these events, including properties such as
source types, implosive (closing) and explosive (opening)
events, compensated linear vector dipole, double-coupling, and
dip, strike and rake characteristics. In turn, producers are using
these attributes to help determine well spacing and orientation,
the number and placement of stages, and forward prediction
through discrete fracture network modeling.
Horizontal drilling has had a major impact on microseismic
acquisition geometry; these geometries have a profound effect
on all of the above aspects. The combination of horizontal drilling
and hydraulic fracturing allows additional “contact” with the reservoir, without which many of these plays would be uneconomic.
The three dominant microseismic field acquisition geometries
are borehole monitoring, true surface monitoring, and shallow
buried grids. Each has distinct advantages, depending on variable
objectives. Collectively, however, the trend has shifted toward hybrid geometries that combine certain components of each of these
three geometries to effectively balance data quality and cost effectiveness.
For example, combining shallow buried arrays and borehole
arrays can produce more accurate moment magnitudes as a function of calibration, using lower-frequency, shallow phones.
Such a hybrid geometry was used to acquire the data in Figure
3, which shows bore hole monitoring (yellow markings) in conjunction with a shallow buried array (blue markings).
We also are seeing combinations of full-aperture shallow buried
grid arrays and reservoir-level borehole arrays, which can drive
superior 3-D imaging accuracy.
Usage Trends
A quick analysis of the three acquisition geometries yields some
insight into usage trends. For example, the key advantage to borehole monitoring is the listening proximity and associated superior signal-to-noise ratios. Because the listening arrays are
close to the reservoir, they can record a high quantity of very small
waves.
The bias clearly is in favor of single-well monitoring, but there
is a noticeable trend toward larger deployment of multiwell geometries. This method generally is good for proximal locations, but
is not ideal for event types.
In comparison, the principal advantage of true surface monitoring is cost and, in theory, a superior 3-D recording array designed for reflection seismic acquisition. The array of phones varies
from a typical base line of 1,000 to upward of 20,000, with the
controlling factors being cost, availability, signal-to-noise mitigation, depth of target, and field issues such as surveying and permits. Because the geophones reside on the surface, they are much
farther from the treatment well.
Additionally, the low-velocity layer (LVL) generally is variable
in depth, composition and velocity, and may have a strong Q component that can greatly attenuate high frequencies and related amplitudes. In general, one captures only the larger microseisms, and
the signal-to-noise ratio can be so low that events are located only
through imaging, and not through first arrival analysis.
Permanently installed, shallow-buried grids have the advantage of residing below the unconsolidated or less consolidated
LVL, which means less absorption, much higher signal-to-noise
ratios, better understood velocities, effective 3-D geometry, and
higher end attributes. Shallow buried grids are an expensive tool
for single-well operations, but because they are permanent, they
can monitor many wells over time. They have the disadvantage
of residing farther from the reservoir, which means they capture
FIGURE 3
Hybrid Microseismic Geometry Combining
Borehole (Yellow) and Shallow Buried Arrays (Blue)
SpecialReport: Oil & Gas Computing
fewer smaller events. They also are potentially more susceptible
to surface or near-surface trapped noises.
On The Horizon
In identifying a range of trends across the full reach of seismic operations–from the basin scale to microseismic–the question that always surfaces is, “What is next?” Some of the trends
discussed in this article have emerged abruptly, while others have
emerged more methodically over time, and many of them are interconnected, but to what do they point on the horizon?
We anticipate aggressive innovation in the seabed seismic segment, since the market for ocean-bottom services has increased
400 percent in only the past eight years. Other innovations can
be expected in terms of both technology and operations, includ-
SCOTT
SINGLETON
Scott Singleton is technical manager for ION Geophysical’s
3-D multiclient data program for unconventional resources. He
began his career in marine acquisition and processing for Western Geophysical, Seiscom Delta, and Digicon. He then worked
on acquiring, processing and interpreting a variety of seismic data
types at Fugro-McClelland Marine Geosciences, and consulted
on quality control methods for seismic acquisition and processing with Energy Innovations Inc. Singleton’s career also includes
working in seismic inversions at Jason Geosystems, rock property and inversion workflows at Core Laboratories, and processing
and interpretation at Rock Solid Images, where he served as seismic technology adviser before joining ION in 2012. He holds a
B.S. in geophysics from the New Mexico Institute of Mining & Technology, and an M.S. in geophysics from Texas A&M University.
ing enhancements to 3-D and 4-D interpretation, along with efficiencies in deployment and turnaround.
We also are monitoring the research and development of multisource geophysics, and where that may lead. Does seismic become just one part of a more complete exploration dataset that
incorporates measures such as gravity gradiometry, electromagnetics, and spectral mapping? What other measurement components may emerge? And how does this multimeasurement
process evolve?
One thing is for certain: The complexity of today’s exploration
projects continues to rise, and the value inherent in a wider set
of geophysical measures will only increase. It is essential to look
beyond seismic to gauge tomorrow’s trends.
r
DAVE
RIDYARD
Dave Ridyard is vice president of strategic marketing for ION’s
GeoVentures business unit. He has responsibility for identifying and commercializing new strategic markets for ION’s geophysical technologies. Ridyard joined ION (then Input/Output)
in 1994, and has served in a number of roles in data acquisition technology development and multiclient business development. He holds a degree in applied physics and electronics from
Durham University.
BRIAN
HORN
JOHN
GILLOOLY
John Gillooly is director of microseismic for ION’s GeoVentures business unit. He previously served as vice president of
microseismic and worldwide data processing at Global Geophysical. Gillooly has 35 years of industry experience with Western Geophysical, PGS, Geokinetics and others, with an emphasis on geophysical processing and management. He holds a degree in geology from Auburn University.
Brian Horn is director of geology and chief geologist for ION’s
GeoVentures business unit. His experience includes integrating
geological, geophysical and geochemical data for analyzing play
fairway and petroleum systems, and regional stratigraphic and
seismic correlations, as well as performing resource assessments.
In addition to exploration projects, Horn has delivered exploitation/development programs designed to identify and evaluate critical reservoir uncertainties for reservoir management strategies
and increased recovery efficiencies. He holds a B.S. and an M.S.
in geology from the University of Colorado, and a Ph.D. in geology and geological engineering from the Colorado School of
Mines.