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- Volume 23, Issue 2, 2005
First Break - Volume 23, Issue 2, 2005
Volume 23, Issue 2, 2005
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A little goes a long way with Fugro’s latest unmanned aeromagnetic survey flying machine
By A. McBarnetIt only weighs 40 lb but the GeoRanger could be the start of something big. Andrew McBarnet reports on the development and introduction of the first commercial unmanned airborne vehicle for high resolution aeromagnetic survey operations in remote and offshore areas.
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New data redefines petroleum potential of the Saba Bank area, Netherlands Antilles
Consultants Richard E. Church (geologist) and Kevin R. Allison (geoscientist) suggest that the reworking of legacy and newer seismic survey data reveal petroleum potential previously overlooked. Saba Bank is a submerged carbonate bank located immediately southwest of the island of Saba in the northeastern Caribbean Sea. It lies at the juncture of the Greater and Lesser Antilles, 200 km east of Puerto Rico and 50 km south of Sint Maarten (Figure 1). The bank is an elliptical platform 10 to 100 m below sea level that covers approximately 2200 km² (Figure 2). Previous exploration activities have defined a Tertiary basin with over 4000 m of Eocene to recent sedimentary fill in the eastern half of the bank, and a western shelf with a thin Tertiary section underlain by a thick pre-Eocene (Cretaceous?) sedimentary sequence. The Tertiary basin and the older shelf area are separated by a major wrench fault (Figure 2). Saba Bank is part of the Netherlands Antilles. Petroleum activities on the bank are administered by Saba Bank Petroleum Resources (SBPR), a company jointly owned by the central government of the Netherlands Antilles and the island governments of Saba, Sint Maarten and Sint Eustatius. Seismic reprocessing has helped define a 200 km² Cretaceous prospect with four-way dip closure on the undrilled western shelf area of Saba Bank. An additional five large prospects and seven leads are situated in the immediate area at various water depths (Figure 3). Saba Bank is not currently licensed for exploration and is available from SBPR under a production sharing agreement with very liberal fiscal terms.
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Reduced Vibroseis cycle time technique increases land crew productivity
Authors J.-J. Postel, J. Meunier and T. BianchiThere are still many challenges in improving land seismic productivity. Here Jean-Jacques Postel*, Julien Meunier and Thomas Bianchi describe a new technique for achieving more effective Vibroseis data acquisition. As oil companies come to expect increasingly detailed knowledge of their reservoirs, demand for ever larger seismic volumes is escalating. Land seismic recorder manufacturers have accommodated this trend by improving equipment reliability and by increasing exponentially the number of channels available in the field. The Vibroseis source, however, remains the weak link in the acquisition chain and represents the bottleneck in production. Better source productivity will be key to meeting oil company demand and CGG has been addressing this issue with the development of a new technique.
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Anadarko Basin survey shows value of multicomponent acquisition
Authors S. Roche, M. Wagaman and H. WattIn this case study of a survey in the Anadarko Basin, Oklahoma, Steve Roche, Mark Wagaman, and Howard Watt of Veritas DGC in Houston show that using both P-wave and converted shear wave data provides better gas production estimates. Interpretation of multicomponent data holds great promise for the exploration and development of oil and gas. Shear-wave propagation is sensitive only to rigidity and density, while compressional-wave propagation is sensitive to rigidity, density and compressibility. Interpreting both P- and S-wave reflectivity offers the ability to discriminate lithology, porosity, fractures and possibly fluid content. Recent advances in seismic recording systems, sensor technology and data processing methods are such that the use of multicomponent data for exploration and development is now an economic reality. Specific case studies such as the Anadarko Basin data show the viability of recording converted-wave data. As the industry moves towards 3C recording there also needs to be assurance that P-wave data quality will not be compromised. These data demonstrate that 3C single-sensor P-wave data quality will meet, and possibly exceed, data recorded using conventional P-wave only surveys, if proper attention is given to the signal-to-noise characteristics in the survey area. This may require higher station density and/or a finer group interval in many cases. This paper has three parts, a description of the North Emerald 3C3D test and resulting P-wave (PP) and converted-wave (PS) data quality, relating the P-wave and converted-wave reflectivity to natural gas production from the Springer Formation, and comparing single sensor MEMS recording to six element geophone array data.
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Full-wave seismic acquisition and processing: the onshore requirement
Authors C.J. Criss, C. Kiger, P.W. Maxwell and J. A. MusserC. Jason Criss, Cara Kiger, Pete Maxwell and Jim Musser of Input/Output explain the company’s approach to full wave imaging and processing and why it is the technology of the future. Full-wave acquisition and processing is fast becoming the new revolution in seismic imaging, just as 3D seismic was a revolution in seismic imaging 20 years ago. But why the need for full-wave imaging? As exploration and production efforts become more sophisticated, geoscientists are required to better define reservoir rock and fluid properties and fluid movements, and more accurately determine drilling locations to meet the challenges. Present geophysical assumptions inherent in conventional 3D imaging limit our ability to image reservoirs and understand their contained fluids well enough to have maximum economic impact. These are assumptions of isotropy, frequency band limits, vertical emergent angle and the requirement for source-generated noise attenuation in the field. Because of these assumptions, 3D imaging as it is currently implemented has peaked in usefulness and is less able to deliver additional economic value. This directly affects our ability to find and develop new reserves at an acceptable risk. In addition to the impact on finding new reserves, currently producing fields are seriously suffering from the diminishing economic impact of current 3D technology.
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How single-sensor seismic improved image of Kuwait’s Minagish Field
Authors A. Shabrawi, A. Smart, B. Anderson, G. Rached and A. El-EmamAyman Shabrawi, Andy Smart and Boff Anderson of WesternGeco, with Ghassan Rached and Adel El-Emam from Kuwait Oil Company, describe how single-sensor, digital seismic recording applied onshore in an environmentally and seismically noisy area delivered a highresolution, high-frequency reservoir image. The Kuwait Oil Company (KOC) and WesternGeco conducted the first point-source/point-receiver (single-sensor) onshore seismic survey in the Middle East in early 2004 as a pilot study under a Joint Technology Agreement. The study investigated and subsequently determined that Q-Land single-sensor acquisition and processing techniques could improve seismic imaging and reservoir characterization of the onshore Minagish Field, for which previous attempts to derive reservoir properties from seismic had been largely unsuccessful. The key to success was the ability to effectively remove noise and preserve signal fidelity and high frequencies in the pre-stack data.
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Drawdown test for a stimulated well produced at a constant bottomhole pressure
Authors I. M. Kutasov and L.V. EppelbaumDetermination of formation permeability and well skin factor is important for forecasting flow rates of oil and gas wells. A new technique for analysing test data for stimulated oil wells produced at a constant bottomhole pressure (BHP) has been developed. The method presented in this paper allows one to calculate the skin factor and estimate the formation permeability. It is assumed that the instantaneous flow rate and time data are available from a well produced against a constant bottomhole pressure. Only records of the flowing time and flow rate data are required to compute the values of the skin factor and formation permeability. A semi-theoretical equation is used to approximate the dimensionless flow rate. Our objective is to validate the new suggested method (prior to conducting a field test) by using a simulated example, where a numerical solution is used as an ‘exact’ solution.‘Bottomhole pressure’ means the pressure determined at the face of the producing horizon by means of a pressure-recording instrument. In the case of gas wells or wells having no liquid in the well bore, it means the pressure as calculated by adding the pressure at the surface of the ground to the calculated weight of the column of gas from the surface to the bottom of the hole. Determination of bottomhole pressure (BHP) is an important problem in the oil and gas industry (Akhter and Kreitler, 1990; Schechter, 1992; Yang et al., 2003). At present the majority of well tests are conducted at constant flow rates, where simple solutions of the diffusivity equation can be applied. However, many investigators (Ehlig-Economides and Ramey, 1981; Sengul, 1983; Uraiet and Raghavan, 1980 a.o.) hold to the idea that in practice it is easier to conduct well tests at a constant bottomhole pressure (BHP). It is very difficult to maintain a constant flow rate during long flowing times (especially when testing low permeability formations). The advantages of the constant BHP test are: (1) the fluid production can be easily controlled (at constant flow rate tests the BHP is changing with time); and (2) wellbore storage effects on the test data are short-lived. One of the reasons that constant BHP tests have not been utilized in reservoir engineering is that only numerical solutions of the diffusivity equation for a cylindrical source with a constant BHP have been available. Due to the similarity in Darcy’s and Fourier’s laws, the same differential diffusivity equation describes the transient flow of incompressible fluid in a porous medium and heat conduction in solids. As a result, a correspondence exists between the following parameters: volumetric flow rate, pressure gradient, mobility (formation permeability and viscosity ratio), hydraulic diffusivity coefficient and heat flow rate, temperature gradient, thermal conductivity and thermal diffusivity. Thus, the same analytical solutions of the diffusivity equation (at corresponding initial and boundary conditions) can be utilized for determination of the above-mentioned parameters. Earlier we suggested a semi-theoretical equation to approximate the dimensionless heat flow rate from an infinite cylindrical source with a constant bore-face temperature (Kutasov, 1987). This equation (in terms of pressure and flow rate) was used to process data of step pressure tests when fluid is produced at two successive bottomhole pressures (Kutasov, 1998). The same equation was used to estimate the efficiency of stimulating operations (Kutasov and Kagan, 2003). In both cases a technique for determining the formation permeability and skin factor from flow tests in stimulated wells was developed. The objective of this paper is to suggest a similar technique for determination of the values of formation permeability and skin factor from drawdown constant BHP tests in stimulated wells. We should also like to mention that for damaged wells, when the dimensionless time based on the apparent well radius is very large, a simple equation can be used to process field data (Sengul, 1983; Earlougher, 1977).
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How seismic has helped to change coal mining in China
More LessCoal is the main source of energy in China and accounts for over 65% of the country’s total energy consumption. China’s coal production is the largest in the world and its reserves rank third. Geological reports used for coal mine design and mining production in the past (before 1991, many mines operated without a seismic survey) could only determine faults with displacement larger than 30 m. Such reports fell far below the modern standard needed for mine design and extraction. Because of the poor precision of these geological reports, some mining layouts were unsuitable. Some tunnels and mines have flooded when unexpected geological structures have been encountered. Aware of the enormous economic loss caused by geological unknowns and the potential of high resolution seismic technology, the National Energy Investment Corporation issued a policy document (No.612) in 1991. It required that a seismic survey must be carried out in a coal mine area before any production plan is drawn up. Mining without a pre-production seismic report was forbidden. As a result, the new regulation promoted the application of high-resolution seismic surveys for coal mine construction and production, and marks a landmark in the history of seismic technology in China’s coal industry. From 1991 to 1993, all the seismic surveys were 2D, but it was soon found that the geological reports using 2D were not good enough to meet the needs of coal mine design and production. The first 3D survey in a coal mining area was carried out at Xieqiao coalmine for the Huai Nan Bureau of Mining in 1993. Since then, 3D surveys have been rapidly adopted for coal mines in China. Up to now, 3D surveys account for 95% of all coal mine seismic with 2D surveys making up only 5%. By the end of October 2003, 350 3D surveys projects had been completed covering an area of 600 km2. It has shown that the correct rate of faults with displacement larger than 5 m and caved pillars with a diameter bigger than 20 m verified by seismic survey is over 85% [1]. The detailed geological results have played an important role in optimizing the lay-out of mines. They can also prolong a mine’s production life, improve the safety of the operation, and deliver outstanding economic benefits to coal mining companies in China.
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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)