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

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modulus is equal or slightly less than the dry bulk modulus. We compared the brinesaturated bulk modulus based on measured dry velocities calculated with Gassmann’s equation to the bulk modulus based on measured brine-saturated velocities. The calculated modulus is few percent lower. Data measured on the deep (HP) sands showed a similar trend. We conclude that velocity dispersion is minimal for those porous sands. The fluid-saturation effect is mainly on the bulk modulus as shown in the simplified Gassmann’s equation (Han and Batzle, 2004) Here G (φ) is the gain function, which is a dry rock frame property. Figure 9 shows dry and brine-saturated bulk modulus at high pressure. Data show that dry bulk modulus increases significantly with decreasing porosity: 2.0 GPa at porosity of 35% to 7.0 GPa at porosity of 24%. The brine saturation causes a significant increase of bulk modulus. However, the increment of ∆K tends to be a constant and not sensitive to porosity. Consequently, we can use the increment in bulk modulus ∆Kd to calculate the gain function. (24) Figure 17 shows the gain function for the shallow (VHP) and deep (HP) sand. The gain function for deepwater unconsolidated sands is distributed in a narrow range with the upper bound derived from the Reuss bound and the lower bound constant around 2.5. The gain function decreases with increasing pressure and seems more sensitive to pressure for the HP sands (core damage effect?) than the VHP sands. The lower bound of the gain function seems consistent with (26) higher than those of consolidated reservoir sandstones (Han and Batzle, 2003). Figure 18 shows that brine-saturated velocity is less dependent on porosity. We have developed an empirical model based on Reuss bound to model velocities. The Reuss bound of P-wave modulus is (25) We can derive P-wave velocity as (27) (28) where M0 is P-wave mineral modulus, and assumed equal to 83 GPa. The coefficient n is used to simulate different pressure effect on velocities. For S-wave velocity, a similar model can be used by replacing M0 with grain shear modulus µ0 (assume µ0 is equal to 33 Gpa). This formulation is purely empirical and may be used to describe velocity- Agreement DE-FC26-02NT15342, Seismic Evaluation of Hydrocarbon Saturation 32
pressure-porosity relations. The n value can be calibrated locally. Zimmer et al. (2002) used the modified Reuss model (Dvorkin and Nur, 1996) to simulate the sorting effect on dry velocity-porosity relation for packaged sand samples. We found that their method is not proper for our data because geologic compaction affects the dry velocity-porosity relation of deepwater sands. The laboratory-packed (LS and LGS) sand samples show a sorting effect to reduce porosity, and almost no effect on dry velocities, but a large brinesaturation effect on P-wave velocity of poorly sorted, low-porosity sands. In comparison with laboratory-packed samples, deepwater sands show limited sorting effect and more geologic compaction effect: dry velocities of deepwater sands are significantly higher than those of the LS and LGS sands, and increase with decreasing porosity. The brine saturation effect on bulk modulus remains a constant (constant gain function). Consequently, water-saturated velocities more or less follow the Reuss trend and are less dependent on porosity. P-wave and S-wave relationship Dry P- and S-wave (shear) modulus are related to VP/VS ratio as follows: (29) Figure 19 plots dry shear and P-wave modulus with regression relationship as (30) The relation can be used to derive dry shear modulus from the dry P-wave modulus. At high-pressure, the shear modulus tends to be linearly proportional to P-wave modulus (the red line in Figure 19) with a ratio of 0.42. This ratio is equivalent to k/µ ratio of 1.05. This value tends to increase with decreasing differential pressure. This tight relationship between dry bulk and shear modulus provides an internal constraint on fluid-saturation effects on velocity. Figure 20 shows measured VP/VS ratio versus porosity for dry and brine-saturated samples. The data reveal that dry VP/VS ratio is around 1.6 and did not show significant relation with porosity except slightly increasing with decreasing porosity for samples from the same formation. Under brine-saturated conditions, VP/VS ratio (~2.1) for the deep HP sands is significantly less than for (~2.5) shallow VHP sands. This is due to less compaction and no cementation for the shallow VHP sands with low shear modulus and high porosity. The data also show that the HP water saturated sands have VP/VS ratio that is similar to nearby shale samples. Hydrocarbon indicators in deepwater sands Many hydrocarbon indicators have been proposed (Russell et al., 2003). We propose a DHI with clear physical meaning. In order to identify the fluid from seismic, the key is the sensitivity of fluid effect on P-wave modulus given as: (31) For deepwater, turbidite, unconsolidated sand reservoirs, we can apply the above results to obtain a new hydrocarbon indicator. Assuming, we can determine the porosity of sand frame, bulk modulus of pore fluid (brine) and grain (mineral) modulus, from P-wave Agreement DE-FC26-02NT15342, Seismic Evaluation of Hydrocarbon Saturation 33
Page 1 and 2: June 29, 2006 Seismic Evaluation of
Page 3 and 4: Abstract: During this last quarter
Page 5 and 6: Ursa Data .........................
Page 7 and 8: Figures: Figure 1. Relationship of
Page 9 and 10: Figure 38. Schematic of geometry an
Page 11 and 12: 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: Figure 15. The HP (deep) sands have
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 and 64: MEDIAL LEVEE/OVERBANK 7.62 cm Figur
Page 65 and 66: L1054 L1041 • Ursa Well A4 Green=
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,
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P Impedance Model Synthetic 2 -D Mo
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Above Magenta reservoir model The A
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Figure 73. The extracted wavelet an
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saturation and 50% gas saturation.
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Figure 77. The amalgamated channel
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Figure 79. Channel complex model 2
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Figure 81. AVO stack and gathers fo
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Figure 82. Log signature includes g
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Figure 85. Extracted wavelet and mo
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Figure 87. Amalgamated sheet sand m
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Figure 89. Pseudo logs, wavelet, sy
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Figure 90. Medial basin floor chann
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Figure 92. Pseudo logs, wavelet, sy
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Figure 94. The post stack seismic e
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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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