This document summarizes a presentation on well logging and petrophysical analysis for CO2 storage assessment in the Sabinas Basin in Mexico. It discusses geophysical well logs, petrophysical properties including porosity, clay content, and fluid saturation, and estimates these parameters for a well at 1725 meters. It also briefly outlines the geological structure of formations in the basin based on well and seismic data. The overall purpose is to evaluate potential storage formations and intervals in the Sabinas Basin using well log analysis and petrophysical methods.

1. Well Logging for Petrophysics
Example of the Sabinas Basin
Ricardo Castrejón, UNAM
Advanced Workshop for CO2 Storage
August 26-27, 2014
DF IPN ESIA Ticomán Auditorium
SUPPORTED BY:

2. Acknowledgments:
Ing. Bernardo Martell Andrade, FI, UNAM
Dr. Ricardo J. Padilla y Sánchez, FI, UNAM
Ing. Rafael Acosta, CFE
Ing. Jazmín Mota Nieto, CFE
Ma. Del Carmen Reynoso Martínez, CFE
Rocío Carbajal Martínez, CFE
Mariana Almaraz Espejo
SUPPORTED BY:

3. OUTLINE:
• Sabinas basin
• Geophysical well logs
• Petrophysics
• Storage assessment (Muzquiz-1):
SUPPORTED BY:
Formation temperature
Clay volume
Total porosity
Effective porosity
Lithology
Fluids saturation
Formation water salinity
Estimation of permeability
• Basin model

4. Relationship Between Assessment Scale and Level of
Detail and Resolution
SUPPORTED BY:
(Bachu, 2007)

5. Geological provices with possibility of CO2 storage in
Mexico
SUPPORTED BY:
(CFE, SENER,
2012)

6. Anthropogenic CO2 sources in the region
SUPPORTED BY:
(CFE, 2014)

7. SABINAS BASIN
SUPPORTED BY:
(CFE, Pemex, 2014)

8. GEOPHYSICAL WELL LOGS
SUPPORTED BY:
(Ricco, 2013)

9. GEOPHYSICAL WELL LOGS
SUPPORTED BY:
(Ricco, 2013)

10. PETROPHYSICS
Suitable for CO2 storage in saline aquifers:
• Porosity ≥ 10%
• Permeability ≥ 20 mD
• Clay volume < 15%
• Water saturation = 100%
• Water salinity > 10 Kppm
• Temperature ≥ 35 ºC
• Geothermal gradient: G < 35 ºC/km and/or low Ts
• 800m < Depth < 2,500m
• Pore pressure: hydrostatic
• Evaporites: present
• Thickness ≥ 20m
• Caprock thickness ≥ 10m
SUPPORTED BY:

11. STORAGE ASSESSMENT (WELL MUZQUIZ-1)
• Formation temperature
• Clay volume
• Total porosity
• Effective porosity
• Lithology
• Fluids saturation
• Formation water salinity
• Estimation of permeability
SUPPORTED BY:

12. Formation temperature
SUPPORTED BY:
Data:
Equation:

13. Exercise: calculate
T at 1725 m.
SUPPORTED BY:

14. Exercise: calculate
T at 1725 m.
SUPPORTED BY:

15. Exercise: calculate
T at 1725 m.
Tf = (20 + [(80 - 20) / 2117.5] 1725
SUPPORTED BY:

16. Exercise: calculate
T at 1725 m.
Tf= (20 + [(80 - 20) / 2117.5] 1725
Tf= 68.9 oC
SUPPORTED BY:

17. Clay volume
SUPPORTED BY:

18. Clay volume
SUPPORTED BY:

19. Clay volume
SUPPORTED BY:

20. Clay volume
SUPPORTED BY:

21. Clay volume
SUPPORTED BY:

22. Exercise: calculate Ish and Vsh at 1725 m.
SUPPORTED BY:

23. Exercise: calculate Ish and Vsh at 1725 m.
SUPPORTED BY:

24. Clay volume
SUPPORTED BY:

25. Exercise: calculate Ish and Vsh at 1725 m.
SUPPORTED BY:

26. Exercise: calculate Ish and Vsh at 1725 m.
SUPPORTED BY:

27. Clay volume
SUPPORTED BY:

28. Exercise: calculate Ish and Vsh at 1725 m.
Ish = (38.948 - 5.5824) / (100.22 - 5.5824)
SUPPORTED BY:

29. Exercise: calculate Ish and Vsh at 1725 m.
Ish = (38.948 - 5.5824) / (100.22 - 5.5824)
Ish = 0.353
SUPPORTED BY:

30. Clay volume
SUPPORTED BY:

31. Exercise: calculate Ish and Vsh at 1725 m.
Ish = (38.948 - 5.5824) / (100.22 - 5.5824) = 0.353
SUPPORTED BY:

32. Exercise: calculate Ish and Vsh at 1725 m.
Ish = (38.948 - 5.5824) / (100.22 - 5.5824) = 0.353
Vsh = 1.7 - [3.38 - (0.353 + 0.7)2]0.5
SUPPORTED BY:

33. Exercise: calculate Ish and Vsh at 1725 m.
Ish = (38.948 - 5.5824) / (100.22 - 5.5824) = 0.353
Vsh = 1.7 - [3.38 - (0.353 + 0.7)2]0.5
Vsh = 0.193
SUPPORTED BY:

34. Clay type
SUPPORTED BY:
(Schlumberger,
2010)

35. Total porosity
SUPPORTED BY:
Where:
ΦT is total porosity with liquids
Φ is total porosity with gas
ΦD is density porosity
ΦN is neutron porosity
Exercise: Calculate total porosity at 1725 m.

36. Total porosity
SUPPORTED BY:

37. Total porosity
SUPPORTED BY:

38. Total porosity
SUPPORTED BY:
Where:
ΦT is total porosity with liquids
Φ is total porosity with gas
ΦD is density porosity
ΦN is neutron porosity
Exercise: Calculate total porosity at 1725 m.
ΦT = (– 0.0710) + (0.1439) / 2

39. Total porosity
SUPPORTED BY:
Where:
ΦT is total porosity with liquids
Φ is total porosity with gas
ΦD is density porosity
ΦN is neutron porosity
Exercise: Calculate total porosity at 1725 m.
ΦT = (– 0.0710) + (0.1439) / 2
ΦT = 0.0365

40. Exercise: calculate Ish and Vsh at 1725 m.
Ish = (38.948 - 5.5824) / (100.22 - 5.5824) = 0.353
Vsh = 1.7 - [3.38 - (0.353 + 0.7)2]0.5
Vsh = 0.193
SUPPORTED BY:
Shaly formation

41. Effective
porosity
SUPPORTED BY:

42. Exercise: calculate effective porosity at 1725 m.
SUPPORTED BY:

43. Exercise: calculate effective porosity at 1725 m.
SUPPORTED BY:

44. Total porosity
SUPPORTED BY:
ΦNcl= 0.27
ΦDcl=-0.02

45. Exercise: calculate effective porosity at 1725 m.
SUPPORTED BY:
ΦNC = 0.1439 – 0.193 (0.27)
Φ DC = – 0.0710 – 0.193 (0.02)

46. Exercise: calculate effective porosity at 1725 m.
SUPPORTED BY:
ΦNC = 0.1439 – 0.193 (0.27)
ΦNC = 0.092
ΦDC = – 0.0710 – 0.193 (0.02)
ΦDC = - 0.075

47. Exercise: calculate effective porosity at 1725 m.
SUPPORTED BY:
ΦNC = 0.1439 – 0.193 (0.27)
ΦNC = 0.092
ΦDC = – 0.0710 – 0.193 (0.02)
ΦDC = - 0.075
Φe = (0.092) + (-0.075) / 2

48. Exercise: calculate effective porosity at 1725 m.
SUPPORTED BY:
ΦNC = 0.1439 – 0.193 (0.27)
ΦNC = 0.092
ΦDC = – 0.0710 – 0.193 (0.02)
ΦDC = - 0.075
Φe = (0.092) + (-0.075) / 2
Φe = 0.0085

49. Natural fractures
SUPPORTED BY:
(Schlumberger)

50. Lithology
SUPPORTED BY:

51. Lithology
(Schlumberger, 2010)
SUPPORTED BY:

52. Exercise: estimate lithology at 1725 m.
SUPPORTED BY:

53. Lithology
SUPPORTED BY:

54. Lithology
SUPPORTED BY:

55. Lithology
SUPPORTED BY:

56. Lithology
SUPPORTED BY:

57. Exercise:
estimate
lithology at
1725 m.
ΦN = 0.1439
ΦD = -0.0710
SUPPORTED BY:

58. Exercise:
estimate
lithology at
1725 m.
ΦN = 0.1439
ΦD = -0.0710
Dolomía
arcillosa
SUPPORTED BY:

59. Minerals interpretation
SUPPORTED BY:

60. Minerals interpretation
SUPPORTED BY:

61. Fluids saturation
SUPPORTED BY:

62. Fluids saturation
Cementation exponent “m”
Tortuosity coefficient “a”
CARBONATES
SUPPORTED BY:
SANDSTONES

63. Fluids saturation
SUPPORTED BY:

64. Fluids saturation
SUPPORTED BY:

65. Fluids saturation (Vsh > 15%)
SUPPORTED BY:

66. Gas estimation
SUPPORTED BY:

67. Exercise: calculate formation water resistivity at 1725 m.
SUPPORTED BY:

68. Exercise: calculate formation water resistivity at 1725 m.
SUPPORTED BY:

69. Water saturation
SUPPORTED BY:

70. Exercise: calculate formation water resistivity at 1725 m.
SUPPORTED BY:

71. Exercise: calculate water saturation at 1725 m.
SUPPORTED BY:

72. Exercise: calculate
Sw at 1725 m.
Rsh= 4 ohmm
SUPPORTED BY:

73. Exercise: calculate water saturation at 1725 m.
Sw = 1
SUPPORTED BY:

74. Abnormal overpressure
(Schlumberger)
SUPPORTED BY:

75. Salinity
SUPPORTED BY:
(Schlumberger)

76. Exercise: estimate formation water salinity at
1725 m.
SUPPORTED BY:

77. Exercise: estimate formation water salinity at
1725 m.
Rw = 0.2 ohmm
T = 68.9 oC
SUPPORTED BY:

78. Salinity
SUPPORTED BY:
(Schlumberger) 15 kppm

79. Permeability
Y Tixier: k = C(Φe
3/Sw
SUPPORTED BY:
2) ; C = 50

80. Exercise: calculate permeability at 1725m.
SUPPORTED BY:

81. Exercise: calculate permeability at 1725m.
With Tixier: k = C(Φe
SUPPORTED BY:
3/Sw
2) ; C = 50

82. Exercise: calculate permeability at 1725m.
With Tixier: k = C(Φe
SUPPORTED BY:
3/Sw
2) ; C = 50
k = 50(0.013/12)

83. Exercise: calculate permeability at 1725m.
With Tixier: k = C(Φe
SUPPORTED BY:
3/Sw
2) ; C = 50
k = 50(0.013/12)
k = 0.00005 D
k = 0.1 mD

84. Mud logging
SUPPORTED BY:
(Mud logging)

85. Integration of core analysis
SUPPORTED BY:

86. Intervals selection
SUPPORTED BY:

87. Petrophysical interpretation
SUPPORTED BY:

88. Petrophysical interpretation
SUPPORTED BY:

89. Intervals selection
SUPPORTED BY:

90. Petrophysical interpretation
SUPPORTED BY:

91. Petrophysical interpretation
SUPPORTED BY:

92. Intervals selection
SUPPORTED BY:

93. Petrophysical interpretation
SUPPORTED BY:

94. Petrophysical interpretation
SUPPORTED BY:

95. Intervals selection
SUPPORTED BY:

96. Geological assessment
SUPPORTED BY:
(CFE, 2014)

97. Geological assessment
SUPPORTED BY:
(CFE, 2014)

98. Wells correlation
SUPPORTED BY:
(CFE, 2014)

99. Well formation tops
SUPPORTED BY:
(CFE, 2014)

100. Seismic line
SUPPORTED BY:
(Pemex)

101. Geological sections
SUPPORTED BY:
(CFE, UNAM, software MOVE, 2014)
Sección Monclova

102. Geological sections
SUPPORTED BY:
(CFE, UNAM, software MOVE, 2014)
Sección PN-SAB-2

103. Hosston formation
SUPPORTED BY:
(CFE, UNAM, software MOVE, 2014)

104. Hosston formation
SUPPORTED BY:
(CFE, UNAM, software MOVE, 2014)
Configuración de la
Formación Hosston

105. La Virgen formation
SUPPORTED BY:
(CFE, UNAM, software MOVE, 2014)
Configuración de
la Formación La
Virgen

106. La Peña formation
SUPPORTED BY:
(CFE, UNAM, software MOVE, 2014)
Configuración de
la Formación La
Peña

107. 3D model
SUPPORTED BY:
(CFE, UNAM, software MOVE, 2014)

108. Muchas gracias
SUPPORTED BY: