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- Volume 24, Issue 4, 2006
First Break - Volume 24, Issue 4, 2006
Volume 24, Issue 4, 2006
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Proving up petroleum prospectivity offshore Greenland
By J.C. OlsenJens Christian Olsen, TGS-NOPEC Geophysical Company, explains how the application of ‘good old fashioned geophysics’ may ultimately reveal a world-class deepwater petroleum province offshore West Greenland. Until recently, interest in the petroleum prospectivity offshore West Greenland has been sporadic at best. No surprise then, that exploration off the country’s western coast dates back to a previous era of highpriced oil in the early 1970s. At that time, some 21,000 line km of non-exclusive 2D seismic data were acquired. The surveys provided enough promising geologic indicators to convince six groups of investors, led mainly by major integrated oil companies, to acquire another 16,000 line km of seismic data and to spud five wildcat wells. The spate of exploration in the 1970s was short-lived. All five wildcat wells were declared dry holes and plugged and abandoned. The petroleum industry quickly turned its search for new resources to supply an energy-hungry world to areas perceived to be more promising - and more climatically hospitable - below the Arctic Circle. It was left to the Geological Survey of Greenland, now the Geological Survey of Denmark and Greenland (GEUS), and Greenland’s state oil company, Nunaoil, to reconsider the early seismic and well-control data during the 1990s. They were encouraged in these endeavours by evidence that onshore oil seeps in the Disko-Nuussuaq-Svartenhuk area could be tied to Jurassic, Cretaceous, or Tertiary source rocks. An argument could be made that the region was home to an active petroleum system. Geophysical surveying offshore West Greenland by GEUS and Nunaoil during these years confirmed the presence of cross-cutting reflectors west of Nuuk in the Fylla area and a thick sedimentary geological section off West Greenland’s southern coast near Nuussuaq. Yet, beyond the work of these two state agencies, little new geophysical data were acquired, minimal response was generated by exploration licensing rounds, and exploratory drilling was almost non-existent. However, the sole onshore wildcat drilled onshore Nuussuaq on West Greenland provided a very positive indication that live hydrocarbons were present at least somewhere. When TGS-NOPEC Geophysical Company (TGS) came to Greenland in 1999, only two areas offshore West Greenland were held by licences, and all offshore exploratory drilling wells in the region had been unsuccessful. The total seismic coverage amounted to only 60,000 line km of generally poor to extremely poor quality 2D data, including the 37,000 line km of data acquired in the 1970s. Even today, Greenland is still extremely under-explored, its prospectivity as a petroleum province virtually unknown to the world. Hopefully this may change as a result of work being carried out by a relatively small group including TGS, a handful of oil companies, and officials from GEUS, Nunaoil, and the Bureau of Mineral Resources and Petroleum (BMR). Relying initially on older geophysical data and well-control evidence, these organizations have been collaborating for the past six years on a regional study over a 126,000 km2 area offshore West Greenland. The emerging picture from this regional re-evaluation is a potential world-class petroleum province stretching from the Labrador Sea to the south, northward through the Davies Strait separating Greenland and Canada and into Baffin Bay.
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Survey suggests numerous petroleum plays in the eastern Gulf of Mexico
Authors G.F. Roberts and K. FinstadGlyn Roberts and Kjell Finstad of GGS-Spectrum discuss the implications of a recently acquired 2D seismic survey off western Florida in the eastern Gulf of Mexico, an area that has been off limits to E&P operations in recent years. Owing to a drilling moratorium imposed on the oil industry, very little modern seismic has been acquired in the eastern GOM prior to a recent survey by GGS-Spectrum. The 2D seismic survey (West Florida WF-05 survey) covered a section east and southeast of the original Sale 181 area in the eastern Gulf of Mexico (GOM), running SSE along the Florida Escarpment towards the Dry Tortugas and the EEZ boundary (Fig.1) and covering OCS protraction areas: De Soto Canyon, Florida Middle Ground, Lloyd Ridge, The Elbow, Vernon Basin, and Howell Hook. Its eastern margin is approximately 125 miles from the West Florida coast. Water depths vary from 200 m to 3200 m and the present day bathymetry is dominated by the Florida Escarpment. The seismic data was acquired with an 8000 m streamer, 13 seconds record length and a fold of 107. An environmental impact assessment (EIA) was undertaken prior to survey start up and both marine mammal observers (MMOs) and a passive acoustic monitoring (PAM) system were deployed to assess and mitigate any effects of the survey on marine mammals. The eastern GOM area is one of the last remaining US petroleum frontier areas, and analysis of the results of this survey are intended to allow oil companies and regulatory authorities to more accurately identify potentially commercial volumes of oil and gas and to consider their future development.
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Visualization techniques for enhancing stratigraphic inferences from 3D seismic data volumes
By T. StarkTracy J. Stark, Stark Reality, describes some techniques that he has been developing to visualize bed thickness as a function of relative geologic time using spectral decomposition, ColorStacks, Age volumes, and Seismic-Wheeler volumes. Data visualization techniques allow interpreters to integrate more types of data and extract more usable and pertinent information in significantly less time. It often requires, as in this case, the application of special hardware, software, and display solutions, coupled with experience and proper training. It is helping the interpreters meet the ‘I want it all, I want it now, and I want it right!’ roar of their boss or investors. The ultimate goal is to recognize and convey the maximum amount of geologic information in a minimum amount of time. We want to clearly see what had previously been unseen. This paper makes a few assumptions. First, it assumes that you, the interpreter, would like to see how bed thickness varies, not just as a function of inline, crossline, and travel time, but also as a function of relative geologic time. In other words, along a continuous set of seismic horizons. Second, spectral decomposition, to first order, provides information containing relative bed thickness. Third, the Age volume contains adequate information to convert seismic travel time to relative geologic time. And fourth, it assumes you are not colour blind. Spectral decomposition, Color- Stacks, Age volumes and Seismic-Wheeler volumes have all been described independently in the literature (references later). This is the first time they have all been brought together. Briefly: A ColorStack is where you ‘stack’ data using additive colour instead of additive numbers. With a trained eye, you can see both the forest and the trees using a ColorStack. An Age volume is a seismic volume that contains an estimate of geologic age instead of bandlimited reflectivity. A Seismic-Wheeler volume is a three-dimensional Wheeler diagram (or chronostratigraphic chart) showing the spatial seismic response (or lack thereof during hiatuses) as a function of relative geologic time. For those wanting the bottom line now, jump to Figure 12. It contains colour-coded thicknesses for just a few of a continuous set of relative geologic age horizons: reds represent thicker beds, blues represent thinner beds, while solid grey represents a hiatus (either erosional or non-deposition).
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Effect of regularization in the migration of time-lapse data
More LessWith 4D seismic studies the aim is to look at signal changes in the reservoir which can improve our understanding of the dynamic reservoir system and enable us to optimize production. For a successful study, noise must be minimized as the magnitude of the signal related to the 4D effect is generally weak and the same order of magnitude as the noise. There are many sources of non-repeatability in marine 4D seismic studies from differences in acquisition parameters, differences in environmental factors, and also from data processing effects. When we compare time-lapse datasets, this nonrepeatable noise will remain and impede the interpretation of the data. Pre-stack Kirchhoff Time Migration (PreSTM) is a processing technique utilized in seismic exploration and reservoir monitoring. Such a migration scheme is attractive as it allows the implementation of spatially and temporally varying velocity fields to migrate the data. It is only suitable for datasets with smooth velocity contrasts as any sharp velocity changes (e.g., shallow surface heterogeneities) would leave residual energy visible as a migration smile. Even with smooth velocity variations, another form of migration noise comes from the sub-optimal interference of the migration operator. As the PreSTM implementation uses a symmetrical operator (not the case for Pre-stack Depth Migration), the best possible constructive and destructive interference requires square bins with the midpoint position of the traces at the bin centre. In addition, the traces in a single offset volume should be mono-azimuth (or contain an equally distributed azimuth content for each bin) and mono-offset. When this is not the case residual migration noise will remain as an imprint of the acquisition pattern. In a 4D study where each dataset has slightly different acquisition parameters, each vintage will also have its own pattern of migration noise. This noise is uncorrelated between vintages and appears as energy on the difference section. The use of weighting schemes inside the PreSTM algorithm can help reduce noise by normalizing the migration output. However, regularizing the data on input optimizes the constructive and destructive interference, this handles amplitudes on seismic events as well as attenuating migration smiles. In this paper we consider the level of migration noise from sub-optimal recording positions in a constant velocity medium for a Kirchhoff PreSTM algorithm. In addition, we outline some processing techniques to reduce the level of migration noise.
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Heidrun 2001-2004 time-lapse seismic project: integrating geophysics and reservoir engineering
Authors A. Furre, E. Bakken, T. Kløv and L.H. NordbyDuring the last 10 years, time-lapse or 4D seismic has become a valuable means for improving the understanding of many North Sea reservoirs and establishing better drainage strategies (Landrø and Strønen 2003, Calvert 2005). In this study we demonstrate how time-lapse seismic has contributed to improving the drainage strategy at the Heidrun field and how working in integrated teams helps exploit the full potential of the methodology. We also show how Statoil’s time-lapse seismic inversion procedure has improved the interpretation of intra-reservoir production changes. The Heidrun oil field was discovered in 1985 off the coast of mid-Norway (Figure 1) and has total reserves of 180 million Sm3 of oil and 41.6 billion Sm3 of gas. Approximately 107 million Sm3 of the oil have been exported since production began in 1995. Seismic monitoring is an integral part of an improved oil recovery (IOR) campaign to exploit the remaining reserves. Time-lapse seismic surveys were carried out over the southern part of the Heidrun field (Figure 1) in 2001 and 2004 (Furre et al., 2003 and 2005, respectively), the base survey stemming from 1986. The 2004 survey, however, covered a slightly larger area to gain information to the west of the production platform where an additional production well was to be drilled. The results not only provided a better understanding of the reservoir but also permitted the drainage strategy to be significantly upgraded. The Heidrun field comprises late Triassic to early/mid Jurassic fluvial, deltaic, and shallow marine sandstones of the Åre and upper Tilje formations and the overlying Fangst Group (Figure 2). The field is a heavily faulted horst block and has to be produced in general by draining separate compartments. The aim of the 2004 repeated survey was to better understand the reservoir and improve the drainage strategy for the Fangst and Upper Tilje units which were favourably disposed to time-lapse seismic because of their location and production properties. The seismic data were acquired in September 2001 and June 2004, a time difference of just less than three years (i.e. about half that compared with more than six years of production in the period between the 1986 base line survey and the 2001 repeat survey). The overall drainage strategy for the field is reservoir pressure maintenance by up-flank gas and down-flank water injection - the first row of productions wells being placed accordingly. However, time-lapse seismic was used to optimize the location of new up-flank targets as the wells started to water out. The remaining reserves for each target presently range between 0.25-0.5 million Sm3. The 2001 time-lapse seismic survey results proved valuable for locating four new production wells, while the results from the 2004 survey helped to optimize the positioning of at least one new production well and three new injection wells. The repeated seismic surveys also improved our general understanding of the field’s drainage and helped to increase the knowledge of multi-disciplinary staff engaged in generating flooding maps.
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Seismic history matching in the UKCS Schiehallion field
Authors K.D. Stephen and C. MacBethReservoir managers would like to know the current state of their field and be able to see into the future to know how it will change. The former requires information about current fluid sweep and pressure change while the latter requires accurate reservoir description and a predictive tool such as a simulation model. Important decisions can then be made regarding facility maintenance and well optimization, but more importantly, unswept areas can be identified and new wells drilled. Conventionally, simulation models have been used to determine the possible reservoir state and predict its behaviour. The modelling commonly begins with the geologist who creates a number of static geomodels, often constrained to the core data and the petrophysicist’s well log data in addition to the geophysicist’s pre-production 2D or 3D seismic. The upscaled models are then modified by an engineer so that they match static and dynamic well data, including fluid production rates and local pressures. Because the wells are widely spaced, many possible solutions exist where the well data will match. Time-lapse (4D) seismic can reduce the non-uniqueness by identifying changes in fluid saturation and/or pressures. This information is now available in qualitative form almost routinely in a number of North Sea and Gulf of Mexico fields, but the goal is to integrate this data quantitatively with the modelling process together with other available data. To achieve this goal, we have developed an automated history matching method to include as much reservoir data as is necessary and sufficient, including core and well logs, seismic, production data, SCAL, etc. Here, we apply our method to the Schiehallion UKCS reservoir where we update the operator’s model using geostatistical approaches and obtain an improved match to seismic and a good match to production data. Finally, the uncertainty of the parameters and predicted behaviour is analysed.
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Integration of 4D seismic into the dynamic model: Girassol, deep offshore Angola
Authors J.A. Jourdan, F. Lefeuvre and D. DubucqIn the deep-water environment of West Africa, 3D seismic information is a key factor for exploration, appraisal, development, and monitoring of hydrocarbon fields. To obtain a better understanding of the reservoir, modeling and simulation work was performed, demonstrating that high-resolution (HR) seismic data would provide a more accurate image of the reservoir. The results of this HR survey (Beydoun et al., 2002) had a significant impact on the definition of the Girassol reservoir model by permitting clearer identification of the stacked turbidite channels (Navarre et al., 2002). Girassol was discovered in 1996 off Angola, in water depths up to 1400 m. The field was initially close to the bubble point pressure with no gas cap. After three appraisal wells, the decision was made to launch a fast track development. 4D HR seismic was planned as a reservoir-monitoring tool. The 4D HR data currently consists of a base 3D HR seismic survey shot in 1999 and a monitor 3D HR shot in the two last weeks of 2002. Many people usually think about 4D at the end of a field life, as a way to identify possible by-passed oil. Nevertheless it is now frequently used to acquire 4D early in the field life for monitoring purposes (Goto et al. 2004). In the Girassol case, it was decided to shoot the repeat 3D HR survey after only one year of production and about six months after the start of gas injection. The first reason was to monitor the effect of gas injection in an extremely heterogeneous turbidite environment. The second reason was that, in such a deep offshore environment, the monitoring through re-entry for log measurement is prohibitively expensive. The first results confirmed the ability of 4D to contribute to field monitoring (Dubucq et al., 2003) only four weeks after the last shot had been completed (Lefeuvre et al., 2003). Therefore, based on the excellent quality of the 4D response and on further processing, it was decided to incorporate information from the 4D data into an updated reservoir model. This was done qualitatively in a first phase, which is described in this paper. However, the ultimate goal to use seismic-derived saturation and pressure change distributions to constrain the reservoir model during the history matching process (Gosselin et al., 2003) is not addressed in this paper.
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Volumes & issues
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Volume 42 (2024)
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Volume 41 (2023)
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Volume 40 (2022)
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Volume 39 (2021)
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Volume 38 (2020)
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Volume 37 (2019)
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Volume 36 (2018)
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Volume 35 (2017)
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Volume 34 (2016)
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Volume 33 (2015)
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Volume 32 (2014)
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Volume 31 (2013)
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Volume 30 (2012)
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Volume 29 (2011)
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Volume 28 (2010)
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Volume 27 (2009)
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Volume 26 (2008)
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Volume 25 (2007)
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Volume 24 (2006)
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Volume 23 (2005)
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Volume 22 (2004)
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Volume 21 (2003)
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Volume 20 (2002)
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Volume 19 (2001)
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Volume 18 (2000)
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Volume 17 (1999)
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Volume 16 (1998)
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Volume 15 (1997)
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Volume 14 (1996)
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Volume 13 (1995)
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Volume 12 (1994)
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Volume 11 (1993)
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Volume 10 (1992)
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Volume 9 (1991)
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Volume 8 (1990)
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Volume 7 (1989)
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Volume 6 (1988)
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Volume 5 (1987)
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Volume 4 (1986)
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Volume 3 (1985)
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Volume 2 (1984)
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Volume 1 (1983)