3D Seismic Data Acquisition Research Articles

Acquisition and Preparation of 3D Seismic Data for Pre-Stack Inversion at Siba Oilfield, Southeastern Iraq

The current study includes preparing a geometric proposal of the main parameters that must be worked within a seismic reflection survey to prepare a three-dimensional subsurface image. This image represents the Siba oil field located in Basra, southern Iraq. The results were based on two options for selecting these approved elements to create a three-dimensional image of the Mishrif, Zubair and Yamama formations as well as the Jurassic and Permian Khuff and the pre-Khuff reservoir area. The first option is represented in the geometry in option -1 is 12 lines, 6 shots, and 216 chs. The receiver density is 66.67 receivers / km2, so the shot density is the same. Total shots are 21000, which is the same number of receiving points. The survey area (in km2) and full fold area (in km2) are 317and 328, respectively. However, the second option in the geometry are16 lines, 16 shots, and 208 chs. Receiver density and shot density are 50, while the total shots are 16200 and the total receiving points are 16000; with survey area and full folded area are 198 and 198 km2. The aim of the current study is to characterize the structure and reservoir quality of Yamama and Zubair intervals and to image potential exploration targets such as the Mishrif, Jurassic, Permian Kuff and Pre Khuff formations. The present study succeeded in preparing the geometric proposal and getting at a subsurface image of the reservoir in three dimensions.

OPTIMALISASI DAN ANALISIS DESAIN PARAMETER SEISMIK 3D DARAT BERDASARKAN MODEL GEOLOGI LAPANGAN “RL”

The design of 3D land seismic parameters is a preliminary step before the acquisition of 3D land seismic data to obtain seismic data quality and efficient survey budget. The objective of this research is to obtain high quality of 3D land seismic data based on fold coverage spread on each target layer. The method used is based on the principle of wave propagation or ray tracing method on each target layer, wherein each wave reflection point (bin) will have a different value of fold so that the required configuration of the stretch that will result in the optimal spread of the fold. The applied stretch configurations are orthogonal, brick, zig-zag and slanted where each stretch configuration uses two types of templates that is narrow and wide azimuth. From the simulation analysis results of several stretch configurations in the survey area, then the optimal stretch configuration will be obtained in the survey area. The stretch configuration will be applied is the configuration of orthogonal stretch with narrow azimuth type template. Consideration of the selection of this stretch configuration because it has a more evenly folding effect on the target layer than with other stretch configurations. Furthermore, to obtain the configuration of the appropriate stretch of field conditions, the source point is moved outside the obstacle zone so that the quality of seismic data is maintained.

VSP measurements used as a tool for improving seismic sub-salt imaging in brownfield development

Many of the Paleozoic Rotliegend low-permeability dry gas fields in the Southern Permian Basin of northern Germany are covered by Mesozoic salt dome structures. The resulting complexity in the overburden leads to imaging problems in subsalt reservoirs typically situated at depths between 4000 m to 5000 m TVD. Since structural compartmentalization is often the key challenge in field development, good resolution seismic is essential for well planning. For the study area, only a vintage 3D seismic survey from 1993/94 with limited data quality exists. Acquisition of new 3D seismic data is not possible owing to permitting restrictions and public resistance. Therefore the focus is on the acquisition of 2D VSPs in every new drilled well. The VSP measurements give local insights into the reservoir in the vicinity of the wellbore. With a general structural understanding and production history in mind, those local insights generate immense value for the understanding of the field.

Applications of Geophysical Techniques to Evaluate Deep Formations at Asala-Samra Oil Field, East Bahariya, Egypt

Using the available seismic data, this study aimed at the evaluation of the prospectivity and hydrocarbon potentialities to the deep formations structure of the Asala-Samra area. The Asala-Samra area is located in the Western Desert of Egypt, south of the Northeast Abu Gharadig Concession and west of Qarun oil field. The 3D-Seismic data covers about (56 km2) which called East Bahariya Area. The acquisition of high quality 3D seismic data integrated with the well data resulted in accurate delineation of the structure traps and the different elements of the petroleum system in the study area. The interpretation results of the high quality seismic data contributed to in the understanding of the tectonic history of the study area. Evidences for the presence of Jurassic-Early Cretaceous rifting, Late Cretaceous rifting, Late Cretaceous-Early Tertiary inversion, and Late Tertiary (Miocene) rifting tectonics were documented from the interpretation of the seismic data. The main productive reservoirs of the study area are Abo Roash “G” member and Upper part of Bahariya Formation. This research focused on the deeper formations and structures from Early Cretaceous and Late Jurassic which didn't test as HC trap yet and aims to add new undiscovered zones. Many seismic leads of Early Cretaceous and Late Jurassic were recognized from interpreted seismic data. Most of them are four way dip closure to avoid the side sealing problem. The source rocks are working in the eastern part of the Abu Gharadig Basin. The regional top seals for the different reservoirs in the study area were evaluated through isopach maps. A reservoir evaluation of the Alam Elbueib and Safa sands has been also attempted.

A Geomorphology-centric ranking scheme for stochastic seismic inversion realizations

SUMMARY Advances in the acquisition and processing of 3D seismic data have led to significant improvements in our ability to image subsurface reservoirs. The limitations of conventional 3D seismic measurements for reservoir characterization include its band-limited vertical resolution as well as the non-uniqueness of inverting seismic amplitudes for reservoir properties. These limitations have an impact on our ability to accurately model thin reservoirs for volumetric computations. Stochastic seismic inversion addresses these concerns by producing multiple, equally likely realizations, consistent with the available well and seismic data, at the fine-scale vertical resolution required for such reservoirs. The nature of the algorithm results in a large number of realizations (typically in excess of 200). We, therefore, require a methodology to rank the realizations in a way that is meaningful for the problem at hand and identify models corresponding to the P10 th , P50 th , and P90 th percentiles. In the example presented here a feature recognized on a 3D deterministic seismic inversion result was interpreted as a mitten-shaped tidal bar using well-log data. The stochastic seismic inversion process generated realizations that showed a wide variation in the extent and geometry of the tidal bar. In this work we present an innovative ranking method used to classify the broad range of stochastic inversion results targeted at approximating this tidal bar geomorphological feature. From these results we were successful in identifying the various percentile models required for further analysis including input to reservoir simulation modeling.

Focus on land seismic technology: The near-surface challenge

A new era in land seismic is at hand. Growing energy demand will spur greater efforts in exploration and development into regions of the world where hydrocarbons occur in land environments. Interpreters will require accurate near-surface solutions for mapping low-relief structures and stratigraphic traps, and to improve data quality for placing horizontal wells. This will require solutions to near-surface challenges, such as energy penetration, scattering, source-generated noise, surface-generated multiples, statics, and source and receiver coupling. Solutions to these problems will become possible due to advances in seismic acquisition, including simultaneous source acquisition and wireless seismic-driven ultrahigh channel systems. Additionally, advances in seismic processing technology for processing the resulting huge data volumes will be made possible by continual growth in computational capability. These advances will for the first time allow acquisition of true 3D seismic data. This will not only result in better imaging of the subsurface, but also will allow the near surface to be addressed as an imaging problem with better description of velocities and suppression of surface-related noise.

The geological Hubble: A reappraisal for shallow water

Traditional two-dimensional (2D) seismic acquisition techniques image the subsurface using a grid of orthogonal lines. Dips are recorded only in the along-track direction, limiting migration to a 2D along-track approximation of the inherently 3D wavefields. This produces profiles that are often complicated by out-of-plane reflections and with resolution (for structural interpretation) constrained by the line spacing rather than the source wavelength. The acquisition of true 3D seismic reflection data, in contrast, provides dip information for the reflected wavefields in both along- and across-track directions. This allows a full treatment of the 3D wavefields during migration, affording accurate 3D structural reconstruction, significantly improved resolution (theoretically 1/2 source wavelength), and increasing signal-to-noise ratio (SNR) through more effective noise cancellation.

Vibroseis or Dynamite: investigating source characteristics

A comparison of recently acquired seismic data in the Bowen Basin has highlighted inherent differences in signal content between dynamite and Vibroseis sources. This work was undertaken to assist selection of the source for proposed 2D and 3D seismic surveys in the Bowen Basin where recent drilling successes have revived interest in the hydrocarbon potential of the Permian sequence. Although comparisons between dynamite and Vibroseis sources have been made previously, the topic remains relevant because of developments in acquisition technology, the use of seismic source modelling and the area-dependency of seismic data quality. The motivation for acquisition of further 2D and 3D seismic data in the Surat-Bowen Basin are petroleum discoveries in the Permian Tinowon Sandstone along the western flank of the Taroom Trough at Myall Creek, Churchie, Overston and Waggamba. Variable reservoir quality and extent make identification of Tinowon sands difficult and good quality, high resolution data are essential for exploration and development mapping of the prospective reservoir units. For this study, a pair of overlapping 2D seismic lines was selected, one recorded with a Vibroseis source in 1996 and the other with dynamite in 2000. Care was taken to select two modern lines with acquisition parameters that would minimise the attenuation of frequencies in the higher end of the signal spectrum, thus providing input data sets that would result in a valid Vibroseis-dynamite comparison. Data processing was closely monitored to determine the effects of specific algorithms on signal content. Dynamite proved to have the greatest resolution in the Tinowon zone of interest, that is, around 1400 ms. Indeed, inspection of the signal spectra and particularly the bandpass filter panels on raw field records clearly showed that dynamite data contained higher frequencies and exhibited increased resolution relative to the Vibroseis data in the study area. Bandpass filtering is an effective means of evaluating seismic source characteristics. Predictably, results showed that resolution of the dynamite and Vibroseis data converged with depth due to the natural frequency filter effect of the earth. Synthetic data produced from wavelets matching the Vibroseis and dynamite data demonstrated that the improved resolution expected from the dynamite source would improve imaging of the Permian section. Based on the results of this trial and other modelling, Origin Energy selected a dynamite source for their Myall Creek 3D survey. Mosaic Oil selected dynamite for both their 2003 2D and their 2004 3D seismic survey.

THE NEW ROYAL OIL FIELD: A CASE HISTORY OF THE DISCOVERY AND APPRAISAL OF A SUBTLE, STRATIGRAPHICALLY TRAPPED HYDROCARBON ACCUMULATION IN THE TRIASSIC SHOWGROUNDS SANDSTONE, SURAT BASIN

The New Royal Oil Field is located in a structural embayment on the eastern flank of the Kincora High, western Surat Basin, Queensland. Hydrocarbons have accumulated in the Middle Triassic Showgrounds Sandstone, specifically in a thin basal fluvial unit, interpreted as part of an incised valley fill deposit, that displays excellent reservoir properties but is highly localised in its distribution. The Showgrounds Sandstone overlies either granitic basement or a veneer of Permian clastics including coals. Whereas the Showgrounds Sandstone is an established hydrocarbon bearing reservoir in a number of structural settings elsewhere in the basin, trapping in the New Royal field is primarily stratigraphic.Since its discovery in November 1995, various exploration techniques and technologies have been applied, including the acquisition of 3D seismic data, in an attempt to understand the trapping mechanism of this field and predict its lateral extent, albeit with mixed success. Twelve wells have now been drilled in the greater New Royal field area, only four of which were successfully completed as oil producers from the basal Showgrounds Sandstone. Production to date totals 1.1 million barrels of oil and reservoir simulation studies indicate that original-oil-in-place was 4.6 million barrels.This case history serves as a timely reminder that despite all the technology now available to the petroleum geoscientist, serendipity still plays an important role in the discovery and successful appraisal of certain hydrocarbon accumulations in the Surat Basin.

The Brent Field, Block 211/29, UK North Sea

Abstract The Brent Field was the first discovery in the northern part of the North Sea, and is one of the largest hydrocarbon accumulations in the United Kingdom licence area. There are two separate major accumulations: one in the Middle Jurassic (Brent Group reservoir) and one in the Lower Jurassic/Triassic (Statfjord Formation reservoir). The Brent Field lies entirely within UK licence Block 211/29 at latitude 61°N and longitude 2°E; the adjacent Brent South accumulation extends into Block 3/4A. The water depth is 460 ft. The Brent Field discovery well was drilled in 1971, and was followed by six further exploration and appraisal wells. Seismic data over the Brent Field has been acquired in four separate vintages. The latest acquisition in 1995 allowed detailed mapping of the complex eastern margin of the field for the first time The Brent Field is developed from four fixed platforms (Alpha, Bravo, Charlie, Delta) installed between 1975 and 1978. Production commenced in 1976 and, for the first 22 years of field life, the platforms provided production, water injection and gas injection facilities for both the Brent and Statfjord Formation reservoirs. The Brent South accumulation is produced via the Brent Alpha platform, through sub-sea tie-backs and extended reach wells. In 1992, the decision was taken to depressurize the Brent Field to recover an additional 1.5 TSCF of gas and 34 MMSTB of oil, extending the field's life by 5-10 years. In January 1998, water injection into the main field was stopped and depressurization of the field initiated. As of January 2000, a total of 220 platform wells and three sub-sea wells (173 producers, 50 water injectors) have been drilled in the Brent Field. The original oil/condensate-in-place is currently estimated at 3.8 MMMSTB, and the estimated original wet gas-in-place is 7.5 TSCF. Total ultimate recovery for all reservoirs is expected to be 1988 MMSTB oil and condensate and 6000 BSCF gas. Cumulative oil and net gas production, as of 1st January 2000, was 1875 MMSTB oil and 4196 BSCF gas This paper summarizes the current understanding of the field based on acquisition of new 3D seismic data, 130 new wells, detailed structural and sedimentological modelling, development of the complex crestal part of the field and finally, the initiation of an extensive brown field re-development project to depressurize the reservoir

Measuring The Impact Of 3D Seismic On Business Performance

Three-dimensional seismic has had a major impact on the performance of Amoco's E&P operations. In the last 4 years, 3D seismic has helped improve reserves replacement, improved exploration finding rates and volumes, and had a positive effect on field-reserves revisions. This paper discusses the performance improvements that 3D seismic has brought to the company and suggests ways to measure the impact of emerging technologies. These measures gauge the benefits as well as the easily measured costs when managing technology investments.

Chalk exploration, the search for a subtle trap

Over 2 × 10 9 STB of oil and 8.9 × 10 12 SCF of gas have been produced from the chalk fields of the Greater Ekofisk area, more than 50% of that being produced from the giant Ekofisk Field. Phillips Petroleum Company Norway and the PL018 licence co-venturers have undertaken a comprehensive and integrated re-evaluation of the chalk exploration potential in Blocks 2/4 and 2/7 of the Norwegian Continental Shelf. Recent exploration models indicated the potential for significant untested reserves to exist in the chalk of Blocks 2/4 and 2/7. The Chalk Exploration Project (CEP) team was given the objective ‘to define the risked value of the remaining chalk exploration potential in licence PL018’. All major structures and significant amplitude anomalies at chalk level had been drilled by 1986, leaving only the subtle field flank and stratigraphic plays for evaluation. Although many studies had been completed in the chalk over the years since discovery of Ekofisk Field in 1969, most of these studies had been focused on a single field and no regionally consistent stratigraphic framework or depositional model had been developed. As part of this project, a robust regional model for chalk prospectivity was developed covering the whole chalk basin, based on a sequence stratigraphic analysis of regional seismic and well databases, together with petrophysical, hydrodynamic, geochemical and other key technical studies. Acquisition of 3D seismic data over the chalk fields since the mid 1980s demonstrated the power of 3D seismic analysis to define stratigraphic detail within the chalk, and by 1993 the entire licensed area of Blocks 2/4 and 2/7 was covered by 3D data, giving the opportunity to undertake a semi-regional, sequence stratigraphic 3D analysis of the chalk reservoir in PL018, and determine the remaining exploration potential.

Exploration and appraisal of the South Arne Field, Danish North Sea

The South Arne Field lies in the Danish sector of the North Sea Basin 250 km WNW of Esbjerg on the Danish mainland. It is a chalk field 12 km by 3 km. The field was initially discovered in 1969 by the I-1 well which found a thin Maastrichtian Tor Formation producing up to 4040 BOPD upon test. The second well on the field (Baron-2) was drilled over 20 years later on the southwestern flank. The aim of this well, in addition to targeting deeper Jurassic prospectivity, was to test the concept that the chalk reservoir thickened off-structure. This well encountered no productive chalk reservoir and the prognosed Jurassic reservoir was not reached. Following a change of operator in 1994, the Rigs-1 well was drilled in the northern part of the field where the interpreted structure was most complex. The well was located on 2D seismic data towards the middle of what was interpreted to be a gas cloud. This well encountered a much thicker chalk reservoir sequence than had previously been drilled on the field. Following the acquisition of 3D seismic data and an intensive, integrated geological and geophysical work programme, an appraisal well (Rigs-2) and a down-dip sidetrack were planned in an area outside the gas cloud where the reservoir was predicted to be of high quality. These appraisal wells were very successful in their objectives and proved a stratigraphic element to the hydrocarbon trapping mechanism. The field development plan envisages the extensive use of horizontal wells and first oil is currently scheduled for mid 1999. Reserves are presently estimated to be 89 × 10 6 BBL oil, and 200 × 10 9 SCF of associated gas.

A MULTI-DISCIPLINARY APPROACH TO DEFINITION AND CHARACTERISATION OF CARBONATE SHOALS, SHALLOW GAS ACCUMULATIONS AND RELATED COMPLEX NEAR-SURFACE SEDIMENTARY STRUCTURES IN THE TIMOR SEA

A major exploration program is being undertaken by the AC/P16 Joint Venture in the central Timor Sea, northwestern Australia. Its safe and successful execution is critically dependant on the early definition and characterisation of both the numerous carbonate shoals in the area and the complex bathymetry. This was accomplished via the acquisition of environmental, high-resolution bathymetric, 2D and 3D seismic and airborne laser fluorosensor (ALF) data. Multi-disciplinary integration and analysis of these data have enabled mapping and 3D visualisation of the shoals, and the creation of a 3D velocity model for depth conversion. Seismic amplitude anomalies and chaotic seismic reflectors, which increase in areal extent toward the sea floor, have been interpreted as being due to shallow gas. These gas accumulations are also associated with soft-sediment gravity slides in the shallow sub-surface which exhibit thrust imbrication in the contractional toes and are linked to listric extensional faults. The high resolution bathymetric data have provided images of a disturbed sea floor in several of the areas which are affected by shallow gas: craters, troughs, ridges and mounds can be explained by the localised venting of gas at the sea floor. These gas accumulations are located above basin-scale faults, which are inferred to provide migration paths from more deeply buried source rocks. ALF anomalies mapped at the sea surface, and sea floor grab samples containing petrogenic hydrocarbons, also provide evidence that hydrocarbons are presently leaking from the sea floor.

Exploration in the Gulf of Thailand in deltaic reservoirs, related to the Bongkot Field

Abstract Statoil has been involved in exploration in the Gulf of Thailand since 1985, following an invitation by PTTEP (National Exploration and Production Oil Company of Thailand) to assist in the evaluation and possible development of the Bongkot gas and condensate Field. Statoil and PTTEP jointly studied the field in 1985 and 1986. In 1990 PTTEP farmed 60% out to a group consisting of Total, British Gas and Statoil. Development work on the field started in 1990 with the acquisition of 3D seismic data. The field came on stream in June 1993, and production increased from the original planned 150 10 6 ft 2 /day to 350 10 6 ft 2 /day at present. In the joint PTTEP/Statoil study the Oligocene to Middle Miocene reservoirs were described as fluvial point bar sandstones, deposited in a meandering river system located on a delta top or coastal plain. Based on available data it was not possible to map the individual reservoirs. 22 wells found intermingled gas- and water-bearing sandstones without obvious relation to structure. No field fluid contacts were found, and the pressure regime was thought to be hydrostatic. Statoil simulated a reservoir model consisting of numerous pointbar deposits on a muddy delta plain. The pointbars were assumed to be isolated sandbodies which favoured stratigraphic trapping. Structural mapping of existing 2D and old 3D data sets was thought to give reliable structural maps, although it was difficult to correlate single events. Stratigraphic traps were interpreted as the main traps in the field because no relationship was found between structural closure and gas pools. Since 1990 when field development started with Total as operator around 2500 km 2 of 3D data has been acquired, and approximately 20 exploration wells and 45 development wells have been drilled. These data resulted in a much more accurate description of the field, especially through the use of high-resolution 3D seismic data. The well information allowed the identification of high GR intervals with a continuous seismic expression. Also individual sand reservoirs could be correlated. It became evident from the detailed 3D seismic interpretation that structural traps form the main trapping mechanism, although a minor part of the reserves are found in isolated channel sands, which could be detected from amplitude maps. It has been difficult to identify stratigraphic traps but it is hoped that ongoing seismic attribute analyses will help. In 1993 Statoil farmed in to licence B10/32, operated by Ampolex. The Bongkot model of isolated fluvial channels, with traps formed by several faults with or without structural closure was accepted as an attractive play type. Not withstanding this, the first wildcat well, Karawake-1 was a structural test. The well failed to find hydrocarbons because it intersected a series of overlapping alluvial fans; these lack internal seal and would have precluded hydrocarbon migration and entrapment. Ampolex made a reinterpretation of the block based on the existing 2D seismic, and concentrated on seismic facies mapping. The mapping resulted in two prospect areas where fluvial facies could be recognized above a lacustrine source rock; and also the results of the Karawake-1 well could be better explained. A second well should prove the model.

A hexagonal sampling grid for 3D recording and processing of 3D seismic data

3D seismic data are usually recorded and processed on rectangular grids, for which sampling requirements are generally derived from the usual 1D viewpoint. For a 3D data set, the band region (the region of the Fourier space in which the amplitude spectrum is not zero) can be approximated by a domain bounded by two cones. Considering the particular shape of this band region we can use the 3D sampling viewpoint, which leads to weaker sampling requirements than does the 1D viewpoint; i.e. fewer sample points are needed to represent data with the same degree of accuracy. The 3D sampling viewpoint considers regular nonrectangular sampling grids.The recording and processing of 3D seismic data on a hexagonal sampling grid is explored. The acquisition of 3D seismic data on a hexagonal sampling grid is an advantageous economic alternative because it requires 13.4% fewer sample points than a rectangular sampling grid. The hexagonal sampling offers savings in data storage and processing of 3D seismic data.A fast algorithm for 3D discrete spectrum evaluation and trace interpolation in the case of a 3D seismic data set sampled on a hexagonal grid is presented and illustrated by synthetic examples. It is shown that by using this algorithm the hexagonal sampling offers, approximately, the same advantage of saving 13.4% in data storage and computational time for 3D phase‐shift migration.

Overpressures in the Central North Sea: implications for trap integrity and drilling safety

The Central North Sea Graben is, at pre-Cretaceous levels, a relatively under-explored province of the United Kingdom Continental Shelf. The hydrocarbon potential was recognized in the early 1970s, but both technology and economics prohibited any serious exploration efforts at that time. Exploration for deep targets increased significantly during the second half of the 1980s. This resulted in the discovery and appraisal of several fields, such as the moderately overpressured Marnock and Skua fields and the highly overpressured Erskine, Puffin, Franklin and Heron fields. From a regional viewpoint, the overpressures observed in the pre-Cretaceous reservoirs in the Central North Sea Graben follow a well-defined trend, increasing with depth. Similarly, the minimum effective stresses derived from leak-off pressures measured in the overlying seals follow a comparable trend related to the present-day depth of burial. This indicates that the present distribution of overpressures is controlled by retention and that the understanding of overpressure generation is of second-order importance. A more detailed analysis combining the areal distribution of overpressures with the structural framework suggests that the Central North Sea Graben can be subdivided into several pressure cells. The boundaries between the cells are controlled by faults which, in many instances, show signs of repeated reactivation. This reactivation has led in some cases to failure of otherwise well-defined structural traps, whereas in other cases it may have enhanced the trapping integrity. Examples of intermediate cases can also be recognized, which clearly show that the pressure cells form part of a dynamic system, controlled primarily by the structural evolution of the Central North Sea. A sound understanding of the structural framework and its evolution is therefore of paramount importance in predicting trap integrity and overpressure regimes prior to drilling. The drilling of deep high-pressure/high-temperature wells and the acquisition of modern 3D seismic data permit a continuous improvement in the understanding of overpressures and their distribution.