70th EAGE Conference and Exhibition - Workshops and Fieldtrips

Geothermal energy is playing a larger role as an alternative energy source for both electricity
generation and for space heating. Our recent magnetotelluric (MT) and gravity surveys in
Iceland and Hungary have both characterized known geothermal reservoirs and identified new
drilling opportunities. The success of these surveys has resulted in additional 2D and 3D MT
and gravity data acquisition and the onset of a drilling program to evaluate the identified
geothermal potential.
Higher temperatures and salinity of the pore water, as well as the concomitant increased rock
alteration associated with geothermal areas, often contribute to a decrease in the bulk
resistivity in a rock mass. The zones of low resistivity that are associated with geothermal
reservoirs can be detected by electromagnetic techniques such as the MT method.
We used MT/AMT measurements to acquire natural time varying electrical and magnetic
fields at frequencies of 10,000 Hz ~ 0.001 Hz. The EM field propagates into the Earth as
coupled electrical and magnetic fields and these fields are commonly represented in the
frequency domain as a four element impedance tensor. The characteristics of the MT
resistivity curves are analyzed to extract structural information (associated with resistivity
contrast) that is used to determine high-permeability zones and up flow zones of hydrothermal
systems (Malin, Onacha, and Shalev, 2004).
To complement the MT data, gravity surveys were acquired along the MT survey lines to
assist in detecting fault systems below the surface. Fault system information can be used to
analyze and to understand groundwater channels and water flow directions. At the same time,
gravity data may be used to interpret the subsurface and to aid in locating prospective heat
sources. Integrating the MT and gravity data reduces the intrinsic ambiguity of either dataset
and produces a more robust interpretation.

Offshore hydrocarbon exploration utilizes various remote sensing techniques in order to
increase the knowledge about the subsurface before drilling decisions are made. Seismic
exploration is by far the most common tool and uses acoustic and elastic waves to map
boundaries between subsurface layers with contrasting P- and S-wave velocities. Seismic data
can provide relatively high-resolution information about geological structures and possible
hydrocarbon traps.

The past couple of years have seen a tremendous increase in the acquisition of wide
azimuth (WAZ) surveys that provide improved subsalt imaging. These surveys can
acquire data three times faster than conventional narrow azimuth (NAZ) surveys and at
the same time increase the fold of the data by a factor of five. Therefore we are looking at
processing fifteen times more data while the need for fast delivery of imaged data is
accelerating due to lease expiry, lease sales, drilling decisions and other financial
conditions.

Seismic anisotropy refers to seismic waves traveling with different velocity at different
propagation angle, usually in consolidated, shale-prone areas such as in Gulf of Mexico
and West Africa. A single imaging velocity for any given subsurface location (regardless
of propagation angles) has been commonly used in the industry and is called Isotropic
Migration. Images obtained with Isotropic Migration are often mis-positioned, resulting
in extra cycle time needed to calibrate and correct isotropic images for prospect
evaluation and well planning.

In the last few years the computer assisted tools for horizon picking have improved their
speed, usability and quality of picking so that interpreter's productivity for this task has been
increased by large amounts. Some have quoted productivity gains of three months to one
week. In addition these tools often produce auxiliary outputs of pick quality or stratigraphic
attributes. More recently attention has been focused in helping improve the interpreter's
productivity when performing fault interpretation and framework building. For these tasks
software developments have focused on increased use of coherency and volume curvature.
These attributes are then used to inform automatic fault extraction before detailed
interpretation or fault tracking while interpreting so that fault surfaces are generated with
significantly less manual picking. The result of reducing the effort needed to produce fault
and horizon surfaces has been a huge increase in the number of these surfaces interpreted
within a seismic survey. Semi-automated Structural Framework building then enables these
surfaces and surfaces developed from sub-seismic well correlation to be incorporated into a
very detailed earth model that can be easily populated with reservoir parameters of pressure,
porosity, saturation and permeability. Such models are suitable for use in reservoir simulation
or detailed well planning. The ability to perform all these activities on a single data
representation with computer assistance at each step has removed many of the bottlenecks in
seismic data interpretation and the integration of well and seismic data interpretation.

Here, we will present a set of tools that we find are very well suited to address this challenge. Through our beam migration approach, we are able to efficiently and accurately image large dataset very rapidly and accurately image with a large migration aperture and with a full dip-range. The beam migration process is separated into two main components: a dipscan process that is performed once for the whole survey and which output is then stored on disk for later use, second a fast migration step is carried out ‘on-demand’ or through multiple model iterations. With modern computer hardware this imaging step can be performed in almost real-time. We also present beam-based imaging techniques that allow for more rapid model building in salt-regions through the use of velocity discriminating filtering in the imaging process.

There has been a constant drive to reduce cycle time for depth imaging projects in the
Gulf of Mexico. In recent years, facing impending lease expirations, upcoming lease
sales, and tight drilling schedules, oil companies have continued to compress the cycle
time of Gulf of Mexico depth imaging projects. Seismic companies have increasingly
higher stakes in cycle time reduction, as well. This is a result of the surge of regional
non-exclusive wide-azimuth data acquisition in the Gulf of Mexico's deep waters. To
quickly recoup their companies' investments of hundreds of million dollars, processing
geophysicists in seismic companies are increasingly under pressure to process large
amounts of data in record times. This is in addition to simultaneous demands for
geophysicists to apply the most current technologies, such as, 3D SRME and RTM.

Historically, well targeting in tight gas reservoir plays has
focused on ‘sweet spots” (e.g. high net-to-gross, high Sg,
natural fractures, etc) which aim to highlight areas of
increased productivity. On Sulige, reservoir and
productivity predictions have rarely been straightforward
(no natural fracturing, complex diagenetic history) and the
already-producing wells by Petrochina on North Sulige
more often than not need mechanical stimulation (i.e.
hydraulic fracturing) to maintain prolonged production in
the low permeability, fluvial sandstones.

Norsk Hydro started out their Virtual Reality research activity in 1997 developing an in-house
application in collaboration with Christian Michelsen Research. The application was sold and
commercialized by Schlumberger, known as Inside Reality, but development has separated
the two applications. In HydroVR important application tools were developed in tight
collaboration with the users securing a tight linkage to the daily workflows. The development
and use of HydroVR has been regarded as a success, but have been mainly used by
Production and Research.

Time-lapse seismic acquisition and other temporal monitoring initiatives are becoming
increasingly commonplace. These data, and much additional time-variant information, can be
critical to the decision-making process for reservoir development of mature assets. One of the
best ways of rapidly reconnoitering and analyzing these data is through comprehensive
visualization solutions.
However, current workflows are not conducive to simultaneous visualization of data from
disparate software applications. Time-lapse seismic data, reservoir simulation output, and
production histories are produced in a wide variety of software packages with different
formats and spatial arrangements. Visualization in the same virtual space and time can be an
extremely difficult proposition.
The solution we present makes the import and integration of these data, from many different
sources, an easy and potentially automatic process. By lowering the barriers-to-entry to
visually integrate all the data needed in the reservoir development process, better, faster, and
more accurate decisions can be made.