Geophysics research at the Bureau concentrates on developing multicomponent seismic technology that can be used to better characterize geologic systems. Research effort focuses on design of vector seismic sources, optimization of data-acquisition and data-processing procedures, and unified interpretation of P- and S-wave images. Researchers use 9-component (9-C) seismic data whenever possible as these data allow all seismic wave modes (P, SH, SV, C, fast-S, slow-S) to be used in subsurface imaging. Research involving 3-C and 4-C seismic data is also a key focus area, even though SH and SV modes are not available with these data, as 3-C and 4-C data are acquired by companies more often than are 9-C data.

Current Studies


These four 4-C OBC surveys, Shelf B, Shelf C, Green Canyon NC, and Green Canyon NE, were acquired with source-receiver offsets of 9 and 10 km. This study will concentrate on data from the Shelf B and Shelf C areas.

Imaging Deep Gas Targets with Multicomponent Seismic Data

Bob A. Hardage, principal investigator; Milo M. Backus, Michael V. DeAngelo, Sergey B. Fomel, Khaled Fouad, Robert G. Graebner, Paul E. Murray, Randy L. Remington, and Paul C. Sava

Operators across the Gulf of Mexico (GOM) are targeting deeper and deeper drilling objectives. For deep targets to be evaluated, seismic data are required that have longer and longer source-receiver offsets. Most shallow-water operators in the GOM consider 30,000 ft (9 km) to be the greatest target depth to be drilled for the next several years. For geology at depths of 9 km to be imaged, seismic reflection data must be acquired with offsets of 9 km or more.

This long-offset requirement is difficult to achieve using towed-cable seismic technology in areas that are congested by production facilities, which is the situation for many shallow-water blocks across the northern GOM shelf. Ocean-bottom-cable (OBC) and ocean-bottom-sensor (OBS) technologies are logical options for long-offset data acquisition in congested production areas because ocean-floor sensors, once deployed, are immobile and can be positioned close to platforms, well heads, and other obstructions that interfere with towed-cable operations. An additional appeal of OBC seismic technology is that four-component (4-C) data can be acquired, allowing targeted reservoir intervals to be imaged with P-SV wavefields, as well as P-P wavefields. Once 4-C seafloor receivers are deployed, source boats can maneuver along a receiver line to generate P-P and P-SV data from long-offset distances.

This research is designed to investigate the value of long-offset multicomponent seismic data for studying deep-gas geology across the northern shelf of the GOM. The term long offset means that 4-C OBC data are processed using uniformly sampled source-receiver offsets ranging from 0 to 10 km. The study area is a large, 3,200-mi2 (8,200-km2) section of the Louisiana shelf noted for prolific gas production. Data consist of parallel north-south and parallel east-west 2-D4C profiles spaced at intervals of 2 mi. P-P and P-SV images produced from these long-offset reflection data are interpreted to determine the relative depth-imaging capabilities of each seismic mode. Analysis of these long-offset data shows that the P-P mode contains reflection signals from depths of 60,000 ft (18 km), which is deeper than any reported seismic reflection effort in the GOM basin. Equally important, the critical P-SV mode has a reflection signal from depths of 42,000 ft (13 km).


This map shows multi-client 4-C OBC surveys acquired in the Gulf of Mexico by WesternGeco. This study will utilize short portions of seismic profiles from the Green Canyon NC and Green Canyon NE surveys.

Assessing Deep-Water Gulf of Mexico Gas-Hydrate Systems with Multicomponent and Multi-frequency Seismic Data

Bob A. Hardage, principal investigator; Milo M. Backus, Robert J. Graebner, Paul E. Murray, Randy L. Remington, and Diana C. Sava

The Exploration Geophysics Laboratory (EGL) is a subcontractor to Louisiana State University in this study. Research is funded by the U.S. Department of Interior, Minerals Management Service. The study will investigate several seafloor fluid-gas expulsion sites in the deep-water area of Green Canyon in the northern Gulf of Mexico. Sites will be selected that are traversed by one or more of WesternGeco's deep-water, multiclient, 4-C OBC seismic lines. Multifrequency imaging of gas-hydrate systems associated with these expulsion chimneys will be done by acquiring 2- to 16-kHz chirp-sonar data using an autonomous underwater vehicle (AUV) and 500- to 2,000-Hz data with the Naval Research Laboratory Deep-Towed Acoustic/Geophysics System (DTAGS). These AUV and DTAGS images will then be compared with 4-C OBC images along each profile that is analyzed.


Processing and Interpreting Multicomponent Seismic Data: Gulf of Mexico Seafloor Observatory

Bob A. Hardage, principal investigator; Sergey B. Fomel, Paul E. Murray, and Paul C. Sava

The Exploration Geophysics Laboratory (EGL) is a subcontractor to the Mississippi Mineral Resources Institute (MMRI) in this study. MMRI has received funding from a variety of sources (DOE, MMS, NOOA) to construct a seafloor observatory across a gas-hydrate system in Mississippi Canyon Block 118. EGL's responsibilities are to process and interpret seismic data acquired by the horizontal and vertical arrays of 1-C and 4-C seismic sensors that will be deployed across the observatory. Downgoing P waves from three types of sources will be used to illuminate gas-hydrate strata: conventional surface-positioned air-gun arrays, noise from passing ships, and wind-driven ocean-surface waves. Data will be acquired in a continuous round-the-clock mode when wind-driven surface waves are the imaging source. Data acquisition will be repeated at appropriate calendar-time intervals to investigate dynamic processes that occur in gas-hydrate systems.

CO, DO: Horizontal array (400 m long)
DC: Data Cable
DRS: Data recovery ship
DSS: Data storage system
F: Float
SSD: Station service device
VA1: Water-column vertical array (200 m)
VA2: Subsea vertical array (150 m)
W: Weight (disposable)

The principal components of the seafloor observatory that will operate in Mississippi Canyon Block 118.

Distinguishing Fizz-Gas and Commercial-Gas Reservoirs

This investigation applies 4-component ocean-bottom-cable (4-C OBC) seismic data across gas-producing trends of the Gulf of Mexico to the problem of distinguishing between commercial-gas reservoirs and low-saturation, noncommercial, fizz-gas reservoirs. Attributes of the P-SV mode are combined with calibration log data to classify high-amplitude P-P reflection anomalies into "high-saturation" and "reduced-saturation" categories. Two reservoir examples are provided as Figures 1 and 2. One example is a commercial-gas reservoir; the other is a fizz-gas reservoir. The gas saturation will not be defined for either example so the difficulty of distinguishing between the two types of targets can be appreciated.

Research data utilized in the study are provided by Devon Energy, Seitel Data, and WesternGeco. Funding is provided by EGL sponsors.


Figure 1. P-P and P-SV images of a gas reservoir with known water saturation. Is this a commercial-gas or a fizz-gas reservoir?


Figure 2. P-P and P-SV images of a gas reservoir with known water saturation. Is this a commercial-gas or a fizz-gas reservoir?


Conceptual comparison of conventional seismic stratigraphy and elastic-wavefield seismic stratigraphy. Conventional seismic stratigraphy utilizes only reflected P-wave modes. Elastic-wavefield seismic stratigraphy utilizes all elastic modes P, SH, SV, and C.

Elastic-Wavefield Seismic Stratigraphy: A New Seismic Imaging Technology

Click here for Technical Progress Report (May 2004) posted on DOE Website

Bob A. Hardage, principal investigator; Milo M. Backus, Khaled Fouad, Robert J. Graebner, Jeffrey A. Kane, and Diana C. Sava

The Exploration Geophysics Laboratory (EGL) is partnering with Fasken Oil and Ranch Ltd. and Vecta Technology to develop a new seismic interpretation technology, Elastic Wavefield Seismic Stratigraphy. This technology is based on the physics that each mode of an elastic wavefield can, and often does, image a suite of stratal surfaces differently than do the other elastic modes. Shear (S) modes can image seismic sequences and facies not observed in the compressional (P) mode, which is the only elastic-wave mode used in conventional seismic stratigraphy. In a homogeneous Earth, a full-elastic (9-component) seismic wavefield yields three S-wave modes: SH-SH (horizontal shear), SV-SV (vertical shear), and P-SV (converted shear). In an anisotropic Earth, each of these S modes splits into S1 (fast-S) and S2 (slow-S) modes controlled by the principal axes of anisotropy. Thus, there is a rich source of stratigraphic information in a full-elastic wavefield that is not being utilized in conventional P-wave seismic stratigraphy studies. The objectives of this research are to create compelling examples that prove that different stratal surfaces are imaged by different elastic-wave modes, to develop systematic relationships between petrophysical properties and combinations of elastic-mode sequences and facies, and to demonstrate how this new seismic imaging technology should be applied to improve geologic understanding of oil and gas systems.


Example of coherency attribute data demonstrating that P and C modes image different stratal surfaces and depositional facies associated with an incised-valley depositional system. Seismic times shown on the figures define image depth within the respective data volumes and emphasize the need for developing accurate techniques for correlating image surfaces from different seismic data volumes.

Exploring for Subtle Mission Canyon Stratigraphic Traps with Elastic-Wavefield Seismic Technology

(A study funded by the U.S. Department of Energy and Vecta Exploration)

Bob A. Hardage, principal investigator; Milo M. Backus, Michael V. DeAngelo, Robert J. Graebner, Jeffrey A. Kane, Paul E. Murray, and Diana C. Sava

This study is funded by the U.S. Department of Energy and Vecta Exploration. In its subcontract to Vecta Exploration, Inc., the Exploration Geophysics Laboratory (EGL), is developing a new seismic technology to explore for subtle Mission Canyon oolitic limestone reservoirs in the Williston Basin. This technology will be based on the acquisition and application of full-elastic (9-component) seismic data. Mission Canyon reservoirs are elusive targets when exploration is based on conventional compressional (P) wave seismic data. The attraction of 9-component (9-C) seismic data is that three shear (S) wave modes can also be used for target imaging: SH-SH (horizontal shear), SV-SV (vertical shear), and P-SV (converted shear) modes. Work at EGL has shown that each mode of an elastic wavefield can, and often does, image stratal surfaces across a target interval differently than do other elastic modes. Thus, any of the S modes can depict seismic sequences and seismic facies that are not observed using P waves. This rich, expanded source of stratigraphic and lithofacies information in full-elastic seismic wavefields needs to be utilized in Mission Canyon exploration. The objectives of this study are to acquire, process, and interpret 9C3D seismic data across Mission Canyon plays, develop relationships between drilling objectives and elastic-wavefield attributes, drill confirmation wells, and then share research findings so that full-elastic seismic technology can be applied to improve oil exploration across other areas.

Narrow Azimuth Migration

Sergey B. Fomel, principal investigator

We are developing the theory, numerical algorithm, and prototype implementation of narrow-azimuth migration, a powerful and efficient method for 3-D seismic imaging of marine streamer data.

Narrow-azimuth migration takes advantage of the narrow-azimuth character of data acquired by marine streamers to increase the efficiency of seismic imaging by wavefield extrapolation methods. A new theory is being developed to account for inadequate approximation in common-azimuth migration and corrected for small rotation in the offset azimuth of the propagating wavefield. We anticipate that this theory will lead to a noticeable improvement in current seismic imaging technology. An additional increase in efficiency comes from implementing the narrow-azimuth algorithm on parallel computer clusters.

Differential Azimuth Moveout

Sergey B. Fomel, principal investigator

We are developing the theory, numerical algorithm, and prototype implementation of differential azimuth moveout, a new powerful method for regularizing 3-D seismic reflection data.

In theory, differential azimuth moveout is represented by a partial differential equation, whose role with respect to integral (Kirchhoff) azimuth moveout is similar to the role of the wave equation with respect to Kirchhoff migration. In practice, we anticipate differential azimuth moveout to behave as a compact, local, accurate, and efficiently computed regularization operator. The operator is applied iteratively to produce regular output from irregular input.

Petrophysical Analysis of Multicomponent Seismic Data

Sergey B. Fomel, principal investigator

We are developing new technology for improved multicomponent seismic data analysis. The technology is based on creating angle gathers for both P-wave and S-wave amplitude-versus-angle (AVA) analysis using new powerful wave-equation imaging approaches. Unlike traditional amplitude-versus-offset (AVO) gathers, AVA gathers operate directly in the true reflection angle coordinates, providing a direct assessment for inverting P-wave and S-wave reflectivity for seismic lithology, porosity, and pore fluid content. A joint inversion of multicomponent data in the true angle coordinates opens new possibilities for direct detection of natural gas resources by discriminating between oil, water, and gas content in complex reservoirs during both exploration and production. This technology facilitates exploration in complex geologic areas, improves oil-and-gas reservoir characterization, increases the accuracy of petrophysical attributes estimation, and decreases the much higher costs of exploratory drilling and failed secondary recovery injection projects.

Utilizing 3-D wave-equation migration for seismic imaging is a new approach that has shown great promise in imaging complex deep-water Gulf of Mexico structures. Previously only so-called Kirchhoff methods could be used to generate common-reflection point (CRP) gathers in offset domain and iteratively improve the velocity model used for imaging. Recent research has established a new approach to generating angle-domain common image gathers (ACIG) directly from 3-D wave-equation methods. ACIG's can be used to update the initial velocity model, and they form the basis for a novel method of 3-D amplitude analysis. This technology can be used for gas exploration in deep complex structures over 10,000 ft, where conventional, single-traveltime-arrival, Kirchhoff imaging fails to provide an accurate structural image and wave-equation imaging provides much higher structural resolution and amplitude fidelity. The geophysicist can then obtain higher resolution petrophysical information, linking the accurate seismic amplitude to reservoir properties such as porosity, sand/shale content, water/oil saturation, Vp/Vs ratio, etc.

Seismic Imaging by Riemannian Wavefield Extrapolation

Sergey B. Fomel, principal investigator

We are developing the theory, numerical algorithm, and prototype implementation of seismic imaging by Riemannian wavefield extrapolation (RWE). RWE was proposed by Sava and Fomel (2004) for imaging steeply dipping and overturning reflections in geologically complex exploration areas, such as deep subsalt structures in the Gulf of Mexico.

RWE belongs to the class of wave-equation extrapolation methods that are known to handle accurately large-velocity contrasts, multipathing, and band-limited wave propagation effects. Instead of conventional downward extrapolation, RWE employs a coordinate transformation to extrapolate waves numerically in a direction close to the preferential direction of natural wave propagation. As a result, one can accurately image large propagation angles, including overturning salt-flank reflections, using inexpensive extrapolation operators.


Stratigraphic Section. Formations and rock types penetrated by the test wells.

Devine Test Site 

A Public-Domain Geophysical Field Laboratory Operated by the Exploration Geophysics Laboratory (EGL)

The 100-acre Devine Test Site (DTS) is located less than 50 miles southwest of San Antonio, Texas, in Medina County, Texas (Maps 1 and 2, below). The site is managed by the Exploration Geophysics Laboratory (EGL), an Industrial Associate Program at the Bureau of Economic Geology. It is a state-of-the-art public-domain geophysical research facility for academia and industry donated to UT in 1998 by British Petroleum (BP). The test site is used for surface-based seismic and potential-field experiments performed in conjunction with downhole and crosswell experiments.

The size and shape of the 100-acre field laboratory and the adjacent area for which surface-access rights can be negotiated with property owners is shown on Map 3. BP drilled three test wells (2, 4, 9) during its 12 years of ownership, which are cased to 3,000 ft. Wells 2 and 4 are completed with fiberglass casing to allow for testing of borehole electromagnetic (EM) sources and receivers. These wells are popular with logging companies as resistivity tools can be tested without the complications of steel casing attenuating EM wave propagation. Four shallow (100-200 ft) steel-cased holes are available for borehole-based seismic energy sources and other instrumentation. The wells are in excellent condition. Permanent concrete and gravel pads provide consistent vibrator coupling in a wide range of weather conditions.
Significant upgrades to the site have been made as a result of generous donations by the SEG Foundation. The site now has electricity, flood lights for nighttime use, a water well and water lines, new and refurbished chain fences, new entry gate, tractor mower, and storage sheds.

The stratigraphic section (shown below) breached by the site's 3,000-ft wells is well suited as a field laboratory for geophysical experiments. A key attribute of the site, which appeals greatly to developers of downhole geophysical instruments, is its stable geologic condition. The nearest oil and gas production is several miles away, which ensures that no fluid-exchange processes are occurring in rock facies immediately around the wellbores. Petrophysical properties of the formations, therefore, are well calibrated by numerous historical well logs preserved in the public database. Equipment manufacturers and researchers can also quickly determine if a new tool, a new measurement procedure, or a new petrophysical analysis procedure is providing correct data.


Map 1. Devine Test Site located in south-central Texas.


Map 2. Local map of the Devine Test Site.


Map 3. Test area and key wells.


Map 4. Detail of key wells.