Agreement DE-FC26-02NT15342, Seismic Evaluation of ...

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Figure 49. Large scale levee overbank facies (Courtesy of Slope and Basin Consortium, Gardner et.al., 2006). Summary The aforementioned architectural elements can be seen clearly in outcrop and related to positions along the depositional profile. In the Brushy Canyon formation it is clear that bed thickness is highly variable and dependent upon migration of the channel lobe systems through time (Gardner, et al., 2003). By utilizing the outcrop geometries as well as vertical and lateral changes in facies, the variability can be taken account and will aid in the development of realistic seismic models and help to generate more robust models that represent changes in the channel lobe systems. These observed architectural elements will need to be modified for application to small confined basins typical of the GOM. The sheet sand, channel sands and levee overbank deposits discussed in this chapter will be used to model Ursa deepwater seismic data in the Gulf of Mexico. Ursa Data The Ursa field is one of five prolific producing deepwater fields that are located in the Mars-Ursa intraslope basin, Mississippi Canyon, Gulf of Mexico (GOM). This basin is located approximately 210 km southeast of New Orleans, Louisiana and is in approximately 915-1200 m water depth (Meckel et al., 2002). A map of the basin can be seen in Figure 50. As of 2001, there were five major discoveries in the basin: Mars, Ursa, Crosby, King, and Princess. Agreement DE-FC26-02NT15342, Seismic Evaluation of Hydrocarbon Saturation 64
L1054 L1041 • Ursa Well A4 Green=salt White=non salt Red sq=producing fields Seismic lines L1054 and L1041 Intersect Well A4 Figure 50. Map of the greater Mars-Ursa intraslope basin, Mississippi Canyon, deepwater GOM. Red circle shows Ursa well, blue lines show 2-D seismic. Producing field boundaries shown in red squares. Wells shown in blue circles. (Adapted from Meckel et al., 2002). Between 1989 and 2001, these five major producing fields produced 314 Million Barrels of Oil (MMBO) and 375 Billion Cubic Feet of Gas (BCFG) resulting in 379 Million Barrels of oil equivalent (MMBOE) (Meckel et al., 2002). Each field consists of stacked turbidite reservoirs that have ponded in the salt bounded intraslope confined basins and are Miocene and Pliocene in age. Due to the success of these fields, they have been widely studied and, therefore, have a significant amount of information published about them. In this chapter, the Ursa geologic framework and rock and fluid properties will be discussed. In a later chapter, geobody models developed from the Brushy Canyon outcrops will be calibrated to Ursa subsurface data. Forward models will be built and compared to the Ursa data, which will enhance interpretation of features in seismic and well log data from the Ursa field. Published works will be used to confirm and enhance interpretation. Gulf of Mexico data The Mars-Ursa intraslope basin has a large amount of data. For this study three 2- D seismic lines (images) are available: line 1041, 1054, and 1046. The pre-stack seismic traces for line 1041 are also available. The map of the seismic lines and well log Ursa No 1 tie can be seen in figure 51 according to Hilterman (2001), the 2-D data were acquired by a 6000 m marine streamer with a receiver interval of 25 m and shot interval of 50 m. The reflections from deeper reservoirs have contamination from the salt masses on the far offset traces. Slumping in the first two seconds can affect transmitted amplitude and event timing of deeper reflections (Hilterman, 2001). These issues were addressed with processing that was performed by TGS. One well log (Ursa No. 1) was available for analysis and this log intersects seismic lines 1041 and 1054, as can be seen in Figure 52. The log was received in corrected form by Fred Hilterman, therefore it is assumed that Agreement DE-FC26-02NT15342, Seismic Evaluation of Hydrocarbon Saturation 65
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June 29, 2006 Seismic Evaluation of
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Abstract: During this last quarter
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Ursa Data .........................
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Figures: Figure 1. Relationship of
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Figure 38. Schematic of geometry an
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Figure 73. The extracted wavelet an
Page 13 and 14: Executive Summary: In this joint pr
Page 15 and 16: Results and Discussion Introduction
Page 17 and 18: Inversion of Sw and porosity from s
Page 19 and 20: saturation from seismic data. Valid
Page 21 and 22: The Lagrange function (5) has a sad
Page 23 and 24: ρ ma − ρ + ( ρ w − ρ g ) ×
Page 25 and 26: With a water saturation log calcula
Page 27 and 28: Figure 11. permeability versus poro
Page 29 and 30: Figure 13. Measured dry and brine s
Page 31 and 32: Figure 15. The HP (deep) sands have
Page 33 and 34: pressure-porosity relations. The n
Page 35 and 36: Figure 19. measure dry and brine sa
Page 37 and 38: Relations between Sw, porosity, and
Page 39 and 40: Figure 21. An example realization o
Page 41 and 42: otherwise the seismic properties we
Page 43 and 44: correctly reproduce those found in
Page 45 and 46: study of field data from the Teal S
Page 47 and 48: Figure 30. Spectral decomposed pres
Page 49 and 50: (Adapted from CSM Slope and Basin C
Page 51 and 52: Figure 34. Sequence stratigraphic f
Page 53 and 54: Figure 36. Schematic depiction of c
Page 55 and 56: Figure 38. Schematic of geometry an
Page 57 and 58: Figure 40. Middle slope channel (Ad
Page 59 and 60: Figure 43. Amalgamated sandstone sh
Page 61 and 62: CHANNEL AXIS SINGLE STORY CHANNEL C
Page 63: MEDIAL LEVEE/OVERBANK 7.62 cm Figur
Page 67 and 68: 1.9 miles 37 ft Fizz 19 ft Oil 4.0
Page 69 and 70: esults in shifts followed by subsid
Page 71 and 72: Figure 55. Schematic of depositiona
Page 73 and 74: 4 miles 1.5 s 2 s 3 s Hydrocarbon I
Page 75 and 76: In addition to comparing calculated
Page 77 and 78: Figure 61. Shear velocity trend for
Page 79 and 80: each reservoir interval modeled. Th
Page 81 and 82: Figure 65. Histograms of frequency
Page 83 and 84: the pressure trends were analyzed,
Page 85 and 86: P Impedance Model Synthetic 2 -D Mo
Page 87 and 88: Above Magenta reservoir model The A
Page 89 and 90: Figure 73. The extracted wavelet an
Page 91 and 92: saturation and 50% gas saturation.
Page 93 and 94: Figure 77. The amalgamated channel
Page 95 and 96: Figure 79. Channel complex model 2
Page 97 and 98: Figure 81. AVO stack and gathers fo
Page 99 and 100: Figure 82. Log signature includes g
Page 101 and 102: Figure 85. Extracted wavelet and mo
Page 103 and 104: Figure 87. Amalgamated sheet sand m
Page 105 and 106: Figure 89. Pseudo logs, wavelet, sy
Page 107 and 108: Figure 90. Medial basin floor chann
Page 109 and 110: Figure 92. Pseudo logs, wavelet, sy
Page 111 and 112: Figure 94. The post stack seismic e
Page 113 and 114: Figure 96. Statistically extracted
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Figure 98. The proximal levee overb
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Figure 99. The response of the prox
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Figure 101. The pseudo log, wavelet
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Figure 102. The distal levee overba
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Figure 104. The complex well log ba
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then scaled to the model data by mu
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Figure 107. The Ursa log displays g
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Figure 109. Composite reflection co
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Conclusions One of the main conclus
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Table 5 Summary of the model facies
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REFERENCES Alford, R. M., Kelly, K.
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Gardner, M. H., Anderson, D. A., Bo
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Mahaffie, M.J., 1994, Reservoir cla
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Rothman, D.H., Grotzinger, J.P., Fl
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Vail, P., 1977, Seismic Stratigraph
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downlap (Mtchum, 1977): A base-disc
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direction and downlap onto the tran
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Agreement DE-FC26-02NT15342, Seismi
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APPENDIX E: VALUES USED FOR RESERVO
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