Km Of Seismic Data Research Articles

Paleogene sequence stratigraphic framework of the Faeroe Basin

During Paleogene times up to 15 000 ft (4570 m) of clastic sediment was deposited in the Faeroe Basin, north of the Shetland Islands. A sequence stratigraphic study has shown that the Paleogene deposition in the Faeroe Basin was cyclic with prominent basinward and landward shifts in sedimentation. The correlation of major unconformity surfaces allowed the section to be subdivided into genetically related packages. The sequence stratigraphic study utilized approximately 5000 km of seismic data with a line density of approximately 10 × 20 km. Available well control was integrated into the study by means of synthetic seismograms. Limited palaeontological control utilizing largely dinocysts and radiolaria allowed the identification of 11 Paleocene/Eocene bioevents. The section was subdivided into nine Paleocene and six Eocene sequences, each separated by Type 1 unconformities. Four of the Paleocene and one of the Eocene packages had evidence of multiple Type 1 unconformities and these are described as sequence sets. Sequence development has been related to the tectonic subsidence history of the basin. Early in Paleocene times, rapid subsidence resulted in the deposition of thick sequences with distinct shelf, slope and basinal systems. Nine sequences were deposited with a combined maximum thickness of 12000 ft (3660 m). The following period, late Paleocene to early Eocene, was marked by slower subsidence; thin sequences and ramp systems with seven sequences were deposited with a maximum thickness of 2400 ft (730 m). More rapid subsidence during the late Eocene resulted in five sequences with distinct shelf, slope and basinal systems with a thickness of up to 3500 ft (1070 m). The periods of slower subsidence in the Faeroe Basin may have occurred in response to active rifting in other adjacent basins along the Atlantic margin. The distinct basinal systems which developed during times of more rapid subsidence were more likely to develop sand-prone basin floor deposits.

Structural development and hydrocarbon occurrence of the Carboniferous in the UK Southern North Sea Basin

Recent Carboniferous gas discoveries in the UK Southern North Sea display a pronounced structural alignment. Previous efforts to decipher Carboniferous structural development have been hampered by limited well control and poor quality seismic data. The recent increase in exploration activity in the southern area of Quadrant 44 has facilitated a detailed analysis of the Carboniferous. Interpretation of spectral gamma ray logs and biostratigraphic data from more than 40 deep wells have permitted re-correlation of the Carboniferous section. These new well correlations and VSP data from key wells make it possible to relate seismic reflection character to stratigraphy for several Carboniferous units. More than 2000 km of seismic data were interpreted throughout the southern part of Quadrant 44 to map the distribution of these Carboniferous seismic packages below the angular Base Permian Unconformity. This interpretation project has resulted in a new understanding of Carboniferous structural development and its relationship to hydrocarbon occurrence. East–west-trending hangingwall roll-overs, formed during Carboniferous crustal extension, were subsequently transected by northwest-trending regional anticlines, generated during the Variscan orogeny. Hydrocarbons have been discovered in both the regional anticlines and localized roll-over structures.

Structural and climatic controls on facies distribution in a mixed fluvial and aeolian reservoir: the Triassic Sherwood Sandstone in the Irish Sea

Abstract Interpretation of nearly 5000 km of seismic data, and facies analysis of approximately 900 m of core from 11 wells, has produced structural and sedimentological models of the Triassic Sherwood Sandstone in the East Irish Sea Basin. Sedimentary facies recorded include moderate to low-sinuosity braided fluvial channel, aeolian dune and sandsheet, unconfined fluvial sheetflood and non-evaporitic playa deposits. The establishment of facies associations and correlation of these with wireline logs has enabled extrapolation of sedimentary models into uncored intervals and between wells. The identification of differing seismic character associated with the various facies has made possible the mapping of these diagnostic seismic packages using a seismo-stratigraphic approach. The resulting distribution of seismically derived facies accords with proposed structural and sedimentological models, predicts the position and course of fluvial channels operating in the basin during late Sherwood Sandstone time, and shows that these are largely controlled by fault activity. Detailed facies analysis of sandflat sequences reveals a systematic variation in the proportion of sheetflood and playa to aeolian deposits. It is suggested that this corresponds to a climatic control with sheetflood- and playa-dominated sequences representing relatively wet episodes with a high water table, and aeolian-dominated sequences representing relatively dry episodes with a lowered water table. Correlation of these climatic events may introduce a chronostratigraphic element to the analysis of these continental ‘red-bed’ sequences.

Capricorn and Northern Tasman Basins: Structure and Depositional Systems

The Bureau of Mineral Resources completed a major marine multi-channel seismic reflection survey (MCS) off southeast Queensland in December 1989. The research cruise, using RV 'Rig Seismic: was designed to investigate the structure, stratigraphy and petroleum resource potential of offshore basins along this sector of the Australian continental margin. About half of the 2900 km of seismic data acquired were recorded over the Capricorn Basin and margins of the northern Tasman Basin. The survey included seismic ties to the only deep offshore wells in the region, Aquarius-1 and Capricorn-lA, located in the northern Capricorn Basin. It was the first MCS survey shot in the region since 1974. Sonobuoy refraction, gravity, magnetic and bathymetric data were also collected. The Capricorn Basin evolved in the Late Cretaceous as a failed rift arm at the northern end of the Tasman rift system. From the seismic data, basin development in the Capricorn Basin is seen as typically comprising 0.5 ? 1.0 s twt of syn-rift continental/Irestricted marine deposits (Late Cretaceous-early Palaeogene) overlain by about 1.5 s twt of Eocene-Recent, mainly marine, post-rift sediments. Though basement structures generally follow a north-northwest trend, the structural pattern is complex, comprising a mainly discontinuous series of rift basins of various geometries. Complex structure is also indicated by gravity mapping. Shallow-dipping horizons that extend well into 'basement' may be fault-plane reflections from deep extensional structures, but could also be indicative of large wedges of old (Cretaceous+) sediments or volcaniclastics. In the deep-water southeastern part of the basin, at least 3.6 s twt (4 km) of Late Cretaceous ? Palaeogene section is associated with major half-graben development. A mid-Eocene compressional or transpressional event has reactivated basement structures and produced minor faulting and folding in the section. The event, which also produced significant uplift and erosion, is attributed to intraplate stress resulting from major global plate reorganization that occurred at about 43 Ma. Volcanism was active in the southern Capricorn Basin during Late Oligocene. Volcanic edifices several hundred metres high and 3 to 5 km across are exposed on the seafloor. In the Tasman Basin, a 3-km thick pile of Cainozoic post-breakup sediments overlies oceanic basement and highly extended continental crust at the base of the continental slope to the southeast of Fraser Island. A similar thickness of sediment is present at abyssal depths along the northern transform margin. Large-scale mass movements have taken place on the basin's steep and rugged marginal slopes.

Combined Effect of Tectonism, Eustasy, and Sediment Supply on the Depositional-Sequence History of the Western Offshore, South Africa

Interpreted seismic profiles and maps of depositional systems tracts highlight variations in basin-fill architecture and their inferred causes along western offshore South Africa. Sequence-stratigraphic concepts developed by Exxon were used to interpret 10,000 km of seismic data and logs from 31 exploration boreholes within an area of 90,000 km{sup 2}. Lower frequency second-order supercycles (5-10 Ma) are attributed to changes in the rate of subsidence and are expressed either by predominantly progradational or aggradational depositional supersequence. In addition to these long-duration, basin-wide stratigraphic packages, component depositional sequences that formed in response to third order (1-5 Ma) and higher frequency cycles vary with structural setting within the depobasin, namely depocenter, basin flanks, shelf-edge, and slope systems. High-order sequences are attributed to eustatically driven, high-frequency, base-level changes and/or localized tectonic events (i.e. slope failure, gravity faulting). Variations in the areal distribution of lowstand and shelf-margin systems tracts document lateral shifting sediment supplies and the presence of entrenched feeder-canyons linked to incised valley systems on the shelf. Many canyons, however, terminate updip and may be related to slope failure and headward erosion. The tentative correlation of regionally developed unconformities of the west coast based on microfaunal dating of a limited number of marinemore » condensed sections points to a remarkable correspondence with the Exxon global sea-level chart.« less

A NEW TECTONO-STRATIGRAPHIC SYNTHESIS OF THE NORTH WEST CAPE AREA

The North West Cape area in the Exmouth Sub-basin was the site of the first onshore oil flow in Australia at Rough Range-1 in 1953. Subsequently, exploration focused on two large surface anticlines, Cape Range and Rough Range. By 1984, 30 unsuccessful wells had made it clear that the subsurface was far more complex than indicated by the surface mapping and limited seismic data. A detailed reappraisal of the subsurface structure and stratigraphy was needed.A joint venture group operated by Ampol Exploration began a new phase of exploration by recording over 1200 km of seismic data, both regional and detailed, between 1985 and 1989. An integrated interpretation of seismic data, well information and Landsat imagery has improved the understanding of structural and stratigraphic complexities and has given direction to the current exploration effort.Five of the most significant tectonic episodes to affect the North West Cape area have been recognised. They are Late Carboniferous and Early Jurassic (Sinemurian) rifting phases, Callovian-Oxfordian and Berriasian-Valanginian syn-rift pulses related to break-up and, finally, structural inversion in the Late Miocene. Each of these episodes is associated with characteristic structural styles and stratigraphic sequences.Significant lateral displacement along transfer faults during Sinemurian rifting and again during the Berriasian- Valanginian syn-rift pulse has resulted in the formation of tear faults that swing westward and merge with the plane of the transfer faults. Fault-block rotation and uplift associated with these tear faults provide potential structural and stratigraphic traps. The influence that transfer faults have on the hydrocarbon prospectivity of the North West Cape area has been recognised, including their role in the distribution of reservoir and source rocks.These tectono-stratigraphic concepts have provided a sound framework for future exploration in the North West Cape area, and may have implications for hydrocarbon prospectivity in other parts of the North West Shelf and on passive margins elsewhere.

Structural and Stratigrapic Evolution of the East Georges Bank Basin, Offshore Nova Scotia, Canada: ABSTRACT

The East Georges Bank Basin is located offshore Nova Scotia on the southeastern Canadian continental shelf. The basin covers 2.5 million ac and is one of the last undrilled basins in North America. The geological interpretation is almost entirely based on 16,000 km of seismic data over the basin. Pertinent well control is limited to 10 wells on the US portion of the Georges Bank (West Georges Bank Basin) and two wells on the Scotian shelf. Seismic-stratigraphic analysis of this data has led to a structural and stratigraphic model for the basin. The basin formed during the Triassic when the landmass of Pange began separating along rift zones. A prominent Paleozoic basement high, the Yarmouth Arch separated the East Georges Bank Basin from the West Georges Bank Basin and had a dominant influence on sedimentation until the Middle Jurassic. Early synrift sequences consist of lacustrine clastics and shales. Marine incursions began in the late Triassic resulting in massive salt deposits that reflect the restricted extent of the basin and the arid Triassic and Early Jurassic climate. Further continental separation during the Early Jurassic resulted in deposition of carbonates and evaporites followed by Middle Jurassic continental shelf carbonates and deltaic sands.more » During the Middle Jurassic, major growth faulting and halokinesis was initiated by progradation of the deltaic sands. Post Middle Jurassic continental spreading in combination with changing climatic conditions resulted in a steady decline of carbonate sedimentation and dominance of clastic deposition throughout the remaining history of the basin.« less

Reservoir Delineation by Geophysical Methods in the Suizhong 36-1 Oil Field, Bohai Gulf, China: ABSTRACT

The Suizhong 36-1 oil field is located in Liaodong Bay, People's Republic of China. Oligocene fluviodeltaic and lacustrine sandstones contain over 1 billion bbl of oil in place in a combination structural-stratigraphic trap. An international effort to delineate the reservoirs by geophysical methods was completed in June 1989. Three hundred and fifty kilometers of seismic data were reprocessed and interpreted. An attempt was made to reprocess vertical seismic profile data to better relate seismic data to subsurface reservoir parameters. Unfortunately, incomplete field data and/or documentation made such an effort infeasible. Synthetic seismograms were used for correlation and for wavelet processing of the seismic data. Seismic-petrophysical analyses were done to relate the measurable seismic parameters to the subsurface rock and fluid parameters. Seismic data processing comprised conventional reprocessing, special processing primarily for hydrocarbon indicators, and three-dimensional velocity analysis. The reprocessing of the seismic data improved data quality over that of the original processing. Amplitude vs. offset processing revealed no obvious hydrocarbon indicators in the main reservoir zones. Velocity analysis produced a three-dimensional velocity field that was the key to the interpretation and engineering work that followed. Stratigraphic and structural interpretation was done on a GeoQuest workstation and iterated several times to more » obtain a consistent match with the wells. Seismic attribute generation and analysis were used primarily to reveal patterns associated with the depositional environments. Two kinds of seismic trace inversion processes were used to obtain quantitative estimates of the subsurface acoustic impedance distribution. One, the approximate or pseudoinversion method developed by Lindseth was applied to 300 km of seismic data and was the basis for all the reservoir parameter estimates. « less

Application of seismo-stratigraphic interpretation techniques to offshore West Greenland

A pilot study is being conducted to determine if the use of seismo-stratigraphic interpretation techniques can increase the understanding af the geology of offshore West Greenland in order to reassess the prospectivity of the area. During the period 1975 to 1979, a number of concessions offshore West Greenland were licensed to various consortia of oil companies to search for petroleum. Some 40 000 km of seismic data were acquired, all of which is now released. Five wells were drilled, all of them dry, and all concessions were relinquished by the industry by 1979. The regional geology of offshore West Greenland has been summarised by Manderscheid (1980) and Henderson et al. (1981). They show the West Greenland Basin to consist of fairly uniformly westward dipping sediments bordered near the shelf break by a basement ridge. These authors used what may be termed 'conventional' techniques of seismic interpretation. However, since that time the techniques of seismo-stratigraphy (Vail et al., 1977; Hubbard et al., 1985) have become established. They are now being applied to study seismic data acquired during the mid-1970s.

Sequence Stratigraphy and Depositional Controls in Late Proterozoic-Early Cambrian Sediments of Amadeus Basin, Central Australia

The Amadeus basin is an isolated intracratonic basin at the center of the Australian continent which, because of its location and geometry, provides an ideal opportunity to investigate depositional controls. To this end, more than 6,000 km of seismic data, in conjunction with a field and well-log program, have been used in a study of the late Proterozoic-Early Cambrian Arumbera Sandstone. The Arumbera Sandstone was deposited as two major depositional sequences in a shallow marine and deltaic or coastal-plain setting, similar to that of the Devonian Catskill delta of North America. Sediment was supplied from the southwest by heavily laden, braided streams. During the deposition of the first sequence, when sea level was at its maximum, sedimentation appears to have been largely aggradational as sediment supply balanced or exceeded basin subsidence. The sediments were probably deposited in a coastal or delta plain setting, where small-scale deltas prograded across the carbonate platform sediments of the Julie Formation. During the accumulation of the second sequence, sea level fell rapidly, exposing large areas of sediment deposited during the first cycle and restricting edimentation to two steep-sided, rapidly subsiding subbasins. Deposition was largely progradational, as major deltaic complexes developed on the southern and southwestern margins of the subbasins. Between the major delta complexes, a depositional environment similar to that of the first sequence predominated. In the deep subbasins, the Arumbera Sandstone forms a continuous depositional unit across the Proterozoic-Cambrian boundary. The unconformable nature of that boundary over much of the Earth possibly could be the result of a major eustatic sea level drop. The final geometry of the Arumbera Sandstone and the nature of its sediments were determined largely by local subsidence rates. Subsidence briefly outstripped sediment supply during a stage of crustal extension as the basin evolved during deposition of sequence 1. Depositional space and facies distribution were, however, fine tuned by salt tectonics and major sea level cycles. As at passive margins, sequence boundaries appear to be controlled by sea level cycles. Other variables, such as climate, the lack of vascular plants, and the uplift of the source area were also factors in controlling deposition.

Upper Proterozoic evaporites in the Amadeus basin, central Australia, and their role in basin tectonics

The Amadeus basin, an isolated intracratonic basin in the center of the Australian continent, contains an upper Proterozoic to mid-Paleozoic stratigraphic succession of shallow-marine sediments that, in places, exceeds; 14 km in thickness. The Gillen Member of the Bitter Springs Formation, which occur toward the base of the upper Proterozoic succession, includes evaporites which are among the world9s earliest (∼0.8 to 0.7 Ga). Because of their age, the evaporites have been cited in discussions of sea-water chemistry and have been the focus of scrutiny for early life forms. In spite of their importance, the evaporites are poorly known, particularly from the viewpoint of their depositional and tectonic setting. In an attempt to rectify this deficiency, more than 6,000 km of seismic data were analyzed, in conjunction with a field and well-log study of the unit. The Late Proterozoic Amadeus basin appears to have consisted of two major poorly circulated anoxic sub-basins, which perhaps opened to the ocean to the southeast through the Adelaide geosyncline. Data relating to facies are limited but suggest that deposition of the evaporites was cyclic and followed the patterns identified in other major evaporite basins, the carbonates and sulfates being closer to the basin margins and later stage halite and possibly potassium salts being toward the basin center. The evaporites were deposited in a shallow-marine setting at the time of a relative sea-level high stand. The apparent sea-level high, may relate to basin dynamics, whereas the cyclicity of the evaporites may be due to eustatic sea-level controls acting on the barrier to allow intermittent inflow of sea water. Salt tectonism began shortly after the evaporites were deposited and continued throughout basin development. Consequently, most of the major anticlinal structures have salt cores. The geometry of the salt structures suggests that during their growth, the mean strain rate was 10 −16 s −1 , a rate typical of large salt structures. Growth on these salt structures has played an important role in controlling later sedimentation, particularly during the Cambrian.

THE SUBSURFACE GEOLOGY OF THE WESTERN OFFICER BASIN — RESULTS OF SHELL'S 1980-1984 PETROLEUM EXPLORATION CAMPAIGN

The Officer Basin described in this paper includes four Proterozoic to Lower Palaeozoic sub-basins (Gibson, Yowalga, Lennis, Waigen) which extend in a northwest to southeast belt across 200 000 sq. km of central Western Australia. These sub-basins are bounded by Archaean to Proterozoic basement blocks and are almost entirely concealed by a veneer of Permian and Cretaceous sediments. Depth to magnetic basement locally exceeds eight kilometres.Until recently, information on the sub-surface geology was limited to shallow levels, based on the results of a petroleum exploration campaign in the 1960s and the work of State and Federal Geological Surveys. In 1980, the Shell Company of Australia was awarded three permits (46 200 sq. km) covering the Yowalga and Lennis Sub-basins. The results of 4700 km of seismic data and three deep wildcat wells, combined with gravity, aeromagnetic, Landsat, outcrop and corehole information, has led to a better understanding of the regional subsurface geology.The Lennis Sub-basin appears to contain Lower to Middle Proterozoic sediments, whereas the Yowalga Sub- basin is primarily an Upper Proterozoic to Lower Cambrian sequence which comprises a basal clastic section, a middle carbonate and evaporite sequence and an upper clastic section. Widespread Middle Cambrian basalts cap the Upper Proterozoic to Lower Cambrian prospective sequence. Late Proterozoic uplift resulted in salt- assisted gravity tectonics leading to complex structural styles, especially in the basin axis.Despite oil shows, organic matter in the oil and gas generation windows and reservoir-quality sandstones with interbedded shales, no convincing source rocks or hydrocarbon accumulations have yet been located. The area remains, however, one of the least explored basins in Australia.

THE GEOLOGY AND HYDROCARBON POTENTIAL OF THE NORTH-WESTERN OFFICER BASIN

Recent petroleum exploration in EP 186 and EP 187 in the north-western Officer Basin has greatly increased knowledge of the regional stratigraphy, structure and petroleum prospectivity of the region. This exploration programme has involved the drilling of two deep stratigraphic wells (Dragoon 1 and Hussar 1) and the acquisition of 1438 km of seismic data. Integration of regional gravity and aeromagnetic data with regional seismic and well data reveals that the Gibson Sub-basin primarily contains a Proterozoic evaporitic sequence. In contrast, the Herbert Sub-basin contains a Late Proterozoic to Cambrian clastic and carbonate sequence above the evaporites. This sequence, which was intersected in Hussar 1, is identified as the primary exploration target in the Western Officer Basin. The sequence contains excellent reservoir and seal rocks in association with mature source rocks. Major structuring of the basin has also been caused by compressive movements associated with the Alice Springs Orogeny. The northwestern Officer Basin thus has all of the ingredients for the discovery of commercial hydrocarbons.

Field development with three‐dimensional seismic methods in the Gulf of Thailand—A case history

A three‐dimensional (3-D) marine seismic survey was conducted in the Gulf of Thailand to aid in the development of a gas field indicated by three wildcat wells which had been located by seismic reconnaissance programs shot over a period of several years. The key to successful exploration in the area, basically a hinge line play, was a detailed understanding of the complex faulting controlling the hydrocarbon traps. Since the prospect lies 160–220 km offshore, some specialized surveying techniques were employed to achieve the required positioning accuracy. About 1280 km of seismic data were recorded at 100-m line spacing over a roughly rectangular block covering about [Formula: see text]. The 48‐fold data were processed using a 3-D wave equation migration algorithm yielding a set of seismic traces representing the data vertically below a grid of depth points spaced at [Formula: see text] by 100 m. The results of the 3-D program showed greater fault resolution and structural delineation. The interpretation developed from a series of horizontal slices provided by the 3-D processing further improved fault resolution. Five wells, drilled on the basis of the 3-D survey, are productive and closely tie the seismic data. Initial studies of amplitude patterns of key reflectors, combined with interval velocities from seismic derived logs, appear to offer the potential of direct detection of productive gas zones thicker than 25 to 30 ft. The 3-D seismic data are being utilized for planning additional development wells and potential platform locations.

Definition and Development of Mackerel Field, Gippsland Basin, Australia: ABSTRACT

The Mackerel oil field, located offshore in the Gippsland basin, Australia, was discovered in April 1969. The field, which is a topographic-erosional feature, contains oil in high-quality Eocene-Paleocene reservoir sands which lie beneath an unconformity at the top of Latrobe Group, and is sealed by calcareous shales and mudstone of the Oligocene Lake's Entrance Formation. The initial definition of the field was based on 235 km of seismic data which had been shot in an irregular grid involving seven different surveys and on a total of four exploration wells. At the end of 1974, 145 km of high-resolution seismic data were shot over Mackerel to better define the top of Latrobe unconformity and the internal reservoir configuration. In 1976 a detailed pre-development structur l interpretation was undertaken and a stratigraphic model of the field was constructed from detailed analysis of the seismic data. The pre-development seismic structural and stratigraphic mapping was used to determine the final platform location and to choose the initial development well locations. These well locations were picked to gain early structural control on the top of Latrobe, to test the interpretation in the problem areas, and to investigate the internal geometry of the reservoir units. Development drilling started in July 1977, and these well results have provided feedback to both the structural and stratigraphic models, which are being continuously updated. The pre-development mapping of the Mackerel field was successful in delineating the basic size and shape of the field and its internal stratigraphic configuration and in identifying all the geophysical and geologic problems which were subsequently encountered in the development drilling. Thus a rigorous seismic interpretation provided the geologists and engineers with a sound basis for field development planning. End_of_Article - Last_Page 746------------

SHELL'S OFFSHORE VENTURE, IN SOUTH AUSTRALIA

Offshore South Australia permit O.E.L. 38 was granted to Shell Development (Aust.) Pty. Ltd. on 1st January 1966. An aeromagnetic survey of 10,300 km, three seismic surveys totalling 10,300 km and five man months of coastal field work were carried out before the permit was reissued at the end of 1968 as three separate permits SA-5, SA-6 and SA-7 under the newly enacted joint offshore legislation. At that time Shell also secured two adjoining deep Water permits SA-10 and SA-11.In the period 1969-70 two seismic surveys totalling some 11,750 km were shot. Given geophysical results, a six well drilling programme was planned to commence early 1972. Two dry wells, Platypus-1 and Echidna-1 were drilled in early 1972 in SA-6 and SA-7, with Platypus-1 providing some geological encouragement.Several more prospects were found in SA-6 and SA-7 by the 1973 and 1974 seismic surveys, but these were so small that further work could not be economically justified. SA-6 and SA-7 were surrendered in late 1975 without further wells being drilled. Potoroo-1 was drilled in early 1975 in SA-5. It severely downgraded the prospectivity of that permit, leading to early relinquishment later in 1975, but provided vital geological information relevant to permits SA-10 and SA-11 where drilling was due to commence in 1978. A detail seismic survey in the latter two permits was shot in 1976. Prior to 1976, the main incentive for exploration of the deepwater play had been the apparent presence of a very large anticlinal trend in the central part of SA-10. Interpretation of the 1976 survey showed this trend to be non-prospective, and as a result SA-10 and SA-11 were relinquished in April, 1977. This ended a venture in which three wells were drilled and 24,546 km of seismic data recorded for a total expenditure of $15,837,000.