Michael V. DeAngelo

Depth registration of P-wave and C-wave seismic data for shallow marine sediment characterization, Gulf of Mexico

Multicomponent seismic data, combining P-wave and converted P-to-SV wave (C-wave) wavefields, provide independent measurements of rock and fluid properties. Unlike P waves, C waves are minimally affected by changes in pore fluids, and in cases of azimuthal anisotropy, will be split into two modes (fast and slow) with differing polarization. The 4C, 3D ocean-bottom cable (OBC) multicomponent seismic data discussed here were acquired in shallow water (<300 ft) offshore Louisiana over approximately 455 miles2 (Figure 1). Because these data are still being marketed to interested oil and gas operators, only data above targeted oil and gas reservoirs (<5000 ft) were used. The P-wave migrated data extend to only 1 s and the C-wave migrated data volume to only 2 s.

Multicomponent seismic data registration for subsurface characterization in the shallow Gulf of Mexico

Using multicomponent ocean-bottom seismic technology, it is possible to obtain robust estimates of several subsurface parameters. We apply an automatic data registration (warping) algorithm to find a mapping between P-wave and convertedwave migrated images. The algorithm improves the matching of the two seismic volumes obtained by previous manual interpretation. There are two main products of this process. First, it improves a combined interpretation of the gas cloud zones that are obscured in the conventional one-component (P-wave) seismic images. Second, interval Poisson ratios get extracted directly from the warping function. This extraction provides a petrophysical characterization of the subsurface at a resolution unobtainable by other methods. Introduction Multicomponent seismic exploration with ocean-bottom technology opens new possibilities for improving seismic imaging and for extracting valuable additional information about subsurface physical characteristics (Stewart et al, 2003). The benefits of using multicomponent data have been proven for imaging through gas clouds and identifying shallow gas hazards (Granli et al, 1999; Englehart et al, 2001; Knapp et al, 2001). Joint interpretation of multiple image components (P-P and P-S images) depends on our ability to identify and register reflection events from similar reflectors. This task is especially challenging in shallow sediments, where the high ratio of Pand S-velocities causes large differences in the corresponding traveltimes. DeAngelo et al (2003) describe a careful strategy of joint P-P and P-S interpretation with application to subsurface characterization in the shallow Gulf of Mexico. In this study, we extend the registration procedure with an accurate automatic algorithm for representing P-S reflection events in the corresponding P-P time. By examining the algorithm performance on simple synthetic data, we observe that the differences in the frequency content of the P-wave and converted-wave data have a major impact on the registration accuracy. We implement a non-stationary spectral balancing method to take these differences into account. Balanced images are then automatically registered (warped) to estimate a point-by-point correlation function. The time derivative of this function produces the time-variable ratio of the P and S seismic velocities. This ratio and the related Poisson ratio are major physical attributes useful for interpreting subsurface structures. Our method enables extracting them directly from time-migrated P-P and P-S images. Application of this technique to data from the Gulf of Mexico reveals the structure of sediments around shallow gas clouds with a resolution unobtainable by other methods. Theory If we denote a P-P seismic image as a function of the vertical P-P traveltime t as P(t) and the corresponding converted-wave image as a function of the vertical P-S traveltime τ as C(τ), then the relationship between the two images can be expressed as P(t) ≈ a(t) C(w(t)) , (1) where w(t) is the warping function establishing the correspondence of reflection events in the two images, and a(t) is the amplitude gain function compensating for the difference in reflectivity. We assume the reflection events to be correctly positioned laterally in the migrated images so that the differences can be explained by vertical transformations only. The depth-dependent ratio of the P and S velocities expressed in the P-P traveltime coordinate is simply related to the derivative of the warping function γ(t)= 2 w’(t)-1. (2) Equation (2) is usually applied in the form of an interval relationship γ = 2 ∆τ/∆ t – 1 for a layer of time thickness ∆ t (Stewart et al, 2002). It extends naturally to the continuous case, providing continuous depth-variable values of the interval γ that convert into related Poisson’s ratio σ, as follows: σ(t) = 1⁄2 (γ2(t)-2) / (γ2(t)-1) (3)

Defining P-wave and S-wave stratal surfaces with nine-component VSPs

Nine-component vertical seismic profile (9C VSP) data were acquired across a three-state area (Texas, Kansas, Colorado) to evaluate the relative merits of imaging Morrow and post-Morrow stratigraphy with compressional (P-wave) seismic data and shear (S-wave) seismic data. 9C VSP data generated using three orthogonal vector sources were used in this study rather than 3C data generated by only a vertical-displacement source because the important SH shear mode would not have been available if only the latter had been acquired. The popular SV converted mode (or C wave) utilized in 3C seismic technology is created by P-to-SV mode conversions at nonvertical angles of incidence at subsurface interfaces rather than propagating directly from an SV source as in 9C data acquisition.

Major structural elements of the Miocene section, Burgos Basin, northeastern Mexico

Major Miocene structural elements of the Burgos Basin include a regionwide detachment system that connects extensional fault systems throughout the basin with an active diapir belt downdip, a regionwide pattern of downthrown extensional rollover folds, pervasive secondary faults, and salt and shale diapiric masses in the eastern part of the basin. An interpretation of two-dimensional seismic data suggests that the Burgos Basin Miocene section can be divided into four structural domains: expanded zone, Lamprea trend, Corsair-Wanda trend, and diapir belt. The westernmost unexpanded zone is the footwall of the expanded system part of the basin, which overlies a domain of Oligocene extension. Remaining trends represent an extensional accommodation related to the basinward migration of mobile salt and shale, which has produced a relatively uniform structural style in the Miocene section. The structural style observed in the Burgos Basin appears to define a transitional zone between gravitational collapse in the offshore Laguna Madre-Tuxpan shelf to the south and salt-related raft tectonics of the south Texas Gulf Coast.

Integrated 2D 4-C OBC velocity analysis of near-seafloor sediments, Green Canyon, Gulf of Mexico

Using 2D four-component ocean-bottom-cable (2D 4-C OBC) seismic data processed in common-receiver gathers, we developed robust VP and VS interval velocities for the near-seafloor strata. A vital element of the study was to implement iterative interpretation techniques to correlate near-seafloor P-P and P-SV images. Initially, depth-equivalent P-P and P-SV layers were interpreted by visually matching similar events in both seismic modes. Complementary 1D ray-tracing analyses then determined interval values of subsea-floor VP and VS velocities across a series of earth layers extending from the seafloor to below the base of the hydrate stability zone (BHSZ) to further constrain these interpretations. Iterating interpretation of depth-equivalent horizons with velocity analyses allowed us to converge on physically reasonable velocity models. Simultaneous VP and VS velocity analysis provided additional model constraints in areas where data quality of one reflection mode (usually VP in the near-seafloor environm...

Miocene chronostratigraphy, paleogeography, and play framework of the Burgos Basin, southern Gulf of Mexico

This study characterizes Miocene chronostratigraphy and plays in the Burgos Basin and adjacent south Texas within an area of approximately 39,700 km2 (15,300 mi2), onshore and offshore (to the 500-m [1640-ft] isobath). Using greater than 40,000 linear kilometers (25,000 mi) of two-dimensional seismic lines, 115 onshore wells, 9 offshore wells, and paleontological data, we established a correlation framework of 9 key surfaces (upper Oligocene to lower Pliocene) representing major (probably third-order) sequence boundaries and maximum flooding surfaces throughout the basin. Five of the Burgos Miocene surfaces coincide with regional chronostratigraphic surfaces from the Veracruz and Laguna Madre-Tuxpan basins, thus establishing a consistent correlation framework throughout much of the Mexican Gulf Coast Basin. Twenty Miocene plays are defined by four age divisions (lower Miocene, middle Miocene, upper Miocene_1, and upper Miocene_2) and four paleogeographic settings (unexpanded and expanded shelf, proximal slope, and distal slope). Because of proven high productivity in salt-bounded basins in the northern Gulf of Mexico, the onlap of strata onto diapirs in the eastern Burgos salt province was evaluated as a fifth setting. The paleogeographic provinces and onlap areas exhibit characteristic seismic facies, stratal geometries, and structural relations; a characterization of each one of these being key to the overall play evaluation. This play framework provides the means for continuing exploration of Miocene strata and evaluation of key play elements (reservoir presence and quality, seal, trap, source, and migration and timing) in this structurally complex, underexplored basin. The relative importance of these play elements varies systematically for each play, especially between the onshore shelf plays and the offshore deep-water plays, where fault complexity and stratigraphic variability are greater.

Multicomponent seismic technology for imaging deep gas prospects

Across the Gulf of Mexico, operators are targeting deeper and deeper drilling objectives. For deep targets to be evaluated, seismic data require relatively long source-receiver offsets. Most shallow-water operators in the gulf consider 30 000 ft (9 km) to be the deepest target depth that will 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 at least 9 km. We suggest in this paper that modern 4-C OBC data can provide good quality P-SV data to such depths and should be integrated into prospect evaluations. Long-offset surveys are difficult to achieve using towed-cable seismic technology in areas congested with production facilities, typical for many shallow-water blocks across the northern Gulf of Mexico shelf. Ocean-bottom-cable (OBC) and ocean-bottom-sensor (OBS) technologies are logical options for long-offset data acquisition in congested production ar-eas because ocean-floor sensors are immobile once deployed and can be positioned quite close to platforms, well heads, or other obstructions that interfere with towed-cable operations. An example illustrating the deployment of ocean-floor sensors through a congested platform complex in part of the area of study is illustrated in Figure 1. A 10-km diameter circle is positioned atop this map of production facilities to illustrate the difficulty of towing a 10-km cable across the area in any azimuth direction. In contrast, OBC lines AA, BB, and CC (actual profiles used in this study) pass within a few meters of several production platforms. Figure 1. 4-C OBC data acquisition across congested areas. An additional appeal of OBC seismic technology is that 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 …

3-D seismic detection of undrilled prospective areas in a mature province, South Marsh Island, Gulf of Mexico

This paper focuses on the most effective approach to defining additional resources using 3-D seismic as the sole data source. Although this example is from a densely drilled province, such a seismic-based approach is often used in frontier areas with sparse well coverage, in step-out regions around known production, can be used for a “quick look” evaluation of existing properties, and for real-time interpretation of newly acquired data. This approach—integrating multiple seismic attributes and interpretation methods—refined the structural framework and detected undrilled prospective areas in a mature province in the Gulf of Mexico. Coherency technologies refined the fault interpretations. Surface mapping identified structural highs, and stratal-surface techniques were used to evaluate seismic stratigraphic facies. The study area covered approximately 350 square miles of coastal waters just south of Marsh Island, Louisiana (Figure 1). Data consisted of two merged 3-D surveys, Outer Continental Shelf (OCS) 310 and State Lands (SL) 340 that cover six productive offshore fields: Starfak, Tiger Shoal, Mound Point, Amber Complex, Lighthouse Point, and North Lighthouse Point. Figure 1. Tiger Shoal area in Vermilion Block 50 offshore Louisiana. Sur-rounding fields and the outline of the two major 3-D seismic surveys are indicated. The area is in the Oligocene-Miocene detachment province of the northern Gulf Coast continental margin—a region generally characterized by large-displacement, dominantly down-to-the-basin, listric growth faults that sole on a regional detachment zone above the Oligocene section. Regional deformation is a product of salt mobilization. The faults originate in the autochthonous Jurassic Louann Salt or in the detachment zone represented by a salt weld that formerly contained a thick, allochthonous salt body. A characteristic feature of this province is the thickness (typically exceeding three miles) of deltaic and shelf sediments above the detachment zone. This remarkable stacking of deltaic/shelf sandstone reservoirs helps make this province one of the worlds …

Rock-physics joint inversion of resistivity-log and seismic velocity for hydrate characterization

We present a method for joint inversion of electrical resistivity measurements and velocity data for estimating gas-hydrate concentration in deep-water environments. Our technique is based on a Bayesian approach and combines rock-physics elastic theories and empirical relations for electrical resistivity with stochastic simulations to account for the natural variability of the petrophysical parameters involved in the inversion.

Application of 3C/3D converted mode reflections, King County, Texas

AbstractWe used a 3C/3D seismic reflection data set from King County, Texas, to investigate the utility of multicomponent seismic data for improving reservoir characterization. We evaluated a new seismic processing/interpretation option, based on direct-S modes generated by a vertical-force source. This new seismic mode, SV-P, may allow legacy 3D P-wave data to be reprocessed to create converted-wave data without the need for additional data acquisition costs associated with multicomponent surveys. Using traveltime and amplitude analysis, P-P, P-SV, and SV-P reflectivity was compared to determine which seismic mode might give a clearer picture of the subsurface and subsequently reduce exploration risk.