Enhanced Oil Recovery - Basic

1. Jamal S. Peter
September - 2019
IOR / EOR - Basic

2. 2
Introduction
Rock & Fluid Properties
Special Core & PVT Analysis
Reserve Estimation & Recovery Methods
Well Performance Analysis
Contents :

3. Introduction
3
A. Improved Oil Recovery (IOR) - mobile oil in the reservoir
B. Enhanced Oil Recovery (EOR) - immobile oil

4. Reservoir
Dynamic
Properties
Production
Performance
Maximize
Recovery
Introduction
4

5. 5
Reservoir:
A substance body of rock having sufficient porosity and permeability to store and
transmit fluids; (eg; Sandstone, Carbonate, Fracture Basement … etc...)

6. Rock & Fluid Properties

7. Rock Properties
7

8. 8

9. Porosity Permeability Saturation
9

10. Porosity Permeability Saturation
10

11. Porosity Permeability Saturation
11

12. Porosity Permeability Saturation
1 2 3 4
Energy increases
12

13. Porosity Permeability Saturation
13

14. Porosity Permeability Saturation
14

15. Porosity Permeability Saturation
15

16. Porosity Permeability Saturation
16

17. Porosity Permeability Saturation
17

18. Porosity Permeability Saturation
18

19. Block Well Sample
Depth
(m)
Zone
Ka
(mD)
Swi
(% PV)
Sor
(% PV)
Ko @ Swi
(mD)
Kw @ Sor
(mD)
Ed
(%)
Remarks
Pal-3 4 1289.21 YVI 263 32.4 28.6 148 44 57.7
Pal-3 20 1291.19 YVI 1416 24.2 29.7 915 131 60.8
Pal-3 26 1292.44 YVI 3237 16.6 35.7 2146 245 57.2
Pal-3 31 1292.86 YVI 3851 13.9 37.1 2129 271 56.9
Pal-3 37 1293.47 YVI 5311 13.5 37.8 3127 318 56.3
Pal-3 93 1311.2 YVI 2686 19.7 33.8 1256 108 57.9
Fenti-1 2 1363.18 YVI 4601 22.4 32.5 2470 651 58.1
Fenti-1 9 1364.08 YVI 3820 25.1 29.7 1963 347 60.3
Fenti-1 12 1364.38 YVI 6782 14.2 35.8 3527 771 58.3
Fenti-1 4 1363.59 YVI 10005 13.6 37.7 5605 1476 56.4
Fenti-1 11 1364.23 YVI 6788 15.8 29.9 3572 698 64.5
Fenti-1 15 1364.71 YVI 11900 11.2 33.9 6019 1434 61.8
FM-27 2-014 1271.18 YIV 592 27 31.9 138 0.3 56.3
FM-27 2-017 1271.48 YIV 318 37.6 27.4 62 0.2 56.1
FM-27 2-027 1272.4 YIV 808 36.8 30.5 155 0.2 51.7
FM-27 3-010 1327.49 YVI 641 34.4 25.5 72 0.3 61.1
FM-27 4-009 1332.34 YVI 17897 34.7 23.5 2892 0.3 64.0
FM-27 4-014 1332.84 YVI 11292 36.7 29.3 940 0.4 53.7
FM-27 4-041 1335.74 YVI 4080 36.4 25.9 397 0.3 59.3
FM-27 4-051 1336.81 YVI 2366 26.5 30.2 316 0.4 58.9
FM-27 1-026 1269.58 YIV 912 27.1 36.5 388 0.3 49.9
FM-27 2-002 1269.98 YIV 40.1 31.5 35.6 17 0.1 48.0
FM-27 2-019 1271.68 YIV 2139 25.2 35.9 802 0.3 52.0
FM-27 2-035 1273.13 YIV 4422 24.8 35.4 1607 0.3 52.9
FM-27 3-005 1326.82 YVI 218 28.2 37.3 103 0.2 48.1
FM-27 3-013 1327.75 YVI 2679 24.6 35.4 1357 0.3 53.1
FM-27 3-038 1330.37 YVI 594 28.4 36.5 191 0.2 49.0
FM-27 4-008 1332.24 YVI 7252 23.5 35.2 2305 0.3 54.0
FM-27 4-038 1335.44 YVI 1500 26.8 35.9 828 0.3 51.0
FM-27 4-055 1337.27 YVI 4364 24.7 35.4 1729 0.3 53.0
Corex
unsteady
Corex
steady
Repid
steady
Repid
unsteady
Corex
steady
Fal-5
Fenti
Fal-3
Example of rock properties in Fal & Fenti blocks of Melut basin, DPOC
19

20. Thank You

21. Fluid Properties

22. Bubble point
pressure
Formation
Volume
Vector
Oil Gravity GOR
Fluid Properties
22

23. Oil Gas Water
• Estimating
properties of
reservoir
water is
important
for reservoir
calculations,
specifically
for those
with water
influx
Reservoir fluids
23

24. Bubble Point Pressure
 The bubble point pressure is defined as the
pressure at which the first bubble of gas comes
out of solution.
 At this point, we can say the oil is saturated - it
cannot hold anymore gas. Above this pressure the
oil is under saturated, and the oil acts as a single-
phase liquid.
 At and below this pressure the oil is saturated,
and any lowering of the pressure causes gas to be
liberated resulting in two-phase flow.
24

25. Oil Gravity
 Oil gravity relates the density of oil to that of the density of water.
 API gravity is gradated in degrees on a hydrometer instrument and was
designed so that most values would fall between 10° and 70° API.
 It ranges from 45 °API (light oil) through 20 °API (medium density) to 10
°API (heavy oil). The conversion from API gravity (oil field units) to relative
gravity (relative to water) is:
25

26. Formation Volume Factor
The ratio of the volume of oil and dissolved gas at reservoir (in-situ) conditions to
the volume of oil at stock tank (surface) conditions, volume factors are needed to
convert measured surface volumes to reservoir conditions. It is defined as:
As pressure increases, the amount of solution gas that the oil can dissolve
increases such that the oil swells, and so the formation volume factor exceeds 1.0
oil formation volume factor is dominated by swelling below the bubble point
pressure (due to dissolved gas), and by compressibility above the bubble point
pressure (since all available gas is now dissolved).
 Solution gas
 Compressibility of oil
26

27. Gas Oil Ratio
The solution gas-oil ratio is the amount of gas
dissolved in the oil at any pressure.
GOR increases approximately linearly with
pressure and is a function of the oil and gas
composition. A heavy oil contains less dissolved
gas than a light oil.
The solution gas-oil ratio increases with
pressure until the bubble point pressure is
reached, after which it is a constant, and the oil
is said to be under saturated.
27

28. ρoi Pb GOR Boi Co μoi API Pour Point Acid Asphalten Wax
(g/cm
3
) (psi) (cf/bbl) (m
3
/m
3
) (10
-6
psi
-1
) (cp) (℃) mg (%m/m) (%m/m)
Yabus III Fal-2 DST6 1140.5-1146.0 0.8720 306 42.8 1.063 5.49 42.2 23.0 30.0 3.99 0.28(%wt) 24.6(%wt)
Yabus IV Fal-1 DST6 1203.0-1213.0 0.8521 300 47.0 1.084 5.88 35.5 23.1 42.2 3.20 22.7 21.3
Fal-1 DST5 1243.0-1247.5 0.8545 330 52.2 1.087 6.08 37.6 22.6 42.2 3.50 23.20 20.2
Fal-2 DST4 1183.0-1202.0 0.8521 335 48.0 1.087 6.10 30.4 23.8 42.2 3.50 19.40 30.4
Fal-7 DST2 1315.0-1353.0 0.8321 566 73.2 1.512 6.97 101.7 21.6 39.0 0.40 0.2(%wt) 27.6(%wt)
Fal-9 DST1 1380.5-1393.0 0.8399 380 64.8 1.231 7.20 1082.8 18.1 39.0 0.73 0.25(%wt) 23.8(%wt)
0.8533 333 50.1 1.0870 6.09 34.0 23.2 42.2 3.5 21.3 25.3
Fal-1 DST4 1260.0-1291.0 0.8659 394 56.0 1.088 6.10 41.1 20.7 39.0 4.10 8.50 27.7
Fal-2 DST3 1206.5-1240.0 0.8674 390 54.2 1.082 6.28 30.5 21.9 39.0 3.10 7.20 29.4
Fal-7 DST1 1367.0-1379.0 0.9002 568 89.6 1.075 5.75 86.2 18.6 33.0 6.70 9.15 19.6
0.8778 451 66.6 1.082 6.04 52.6 20.4 37.0 4.6 8.3 25.6
Yabus VII Fal-1 DST3 1311.0-1332.0 0.8833 392 55.3 1.076 6.92 100.0 19.2 27.2 6.80 32.50 4.8
Fal-1 DST2 1343.0-1348.0 0.9112 467 64.0 1.059 5.89 220.0 18.2 39.0 10.40 / /
Fal-2 DST2 1282.0-1302.0 0.8713 455 60.8 1.088 6.37 53.3 21.7 42.2 5.30 26.80 16.6
0.8913 461 62.4 1.074 6.13 136.7 20.0 40.6 7.9 26.8 16.6
Fal-1 DST1 1366.0-1382.0 0.9091 543 74.0 1.085 5.26 362.0 14.5 15.0 8.40 11.30 14.9
Fal-2 DST1 1335.0-1361.0 0.8514 476 48.7 1.035 5.20 201.9 20.0 36.0 1.58 0.21(%wt) 29.9(%wt)
0.8803 510 61.4 1.060 5.23 281.9 17.3 25.5 5.0 11.3 14.9
Yabus IV Fal-3 DST4 1274.5-1285.0 0.8725 347 4.2 1.083 6.02 57.7 21.2 38.9 5.1 27.5 18.4
Fal-3 DST3 1311.5-1317.0 0.8676 409 54.3 1.067 5.43 112.3 23.2 36.0 2.09 0.19(%wt) 23.9(%wt)
Fal-6 DST2 1349.0-1358.5 0.8936 650 75.5 1.085 5.78 158.3 18.2 24.0 8.70 9.05 13.4
0.8806 530 64.9 1.076 5.61 135.3 20.7 30.0 5.4 9.1 13.4
Yabus VI Fal-3 DST2 1331.0-1371.5 0.9001 518 64.2 1.073 5.80 220.4 16.7 33.0 8.70 8.70 3.2
Fal-3 DST1 1376.0-1388.0 0.9205 414 66.5 1.065 4.67 332.0 15.5 22.2 9.80 30.71 7.9
0.9205 414 66.5 1.065 4.67 332.0 15.5 22.2 9.8 30.7 7.9
Fenti-1 DST3 1280.0-1293.0 0.8693 357 53.6 1.078 6.30 50.6 21.3 38.9 4.58 28.55 15.1
Fenti-2 DST4 1314.5-1323.0 0.8100 382 53.1 1.033 8.60 345.3 18.2 30.0 0.35 0.19(%wt) 19.8(%wt)
0.8397 370 53.4 1.055 7.45 198.0 19.8 34.4 2.5 28.6 15.1
Yabus V Fenti-1 DST2 1299.5-1329.0 0.8996 425 57.6 1.061 5.84 106.1 18.1 36.0 0.10 10.10 17.2
Yabus VI Fenti-1 DST1 1362.5-1382.0 0.9061 447 1.064 5.92 298.7 15.5 33.0 9.00 12.05 7.2
DST
Reservoir Condition
Formation
Summary of PVT Analysis Results
Interval
(m)
Yabus IV
Yabus V
Yabus VII
Average
Fal-1
Fal-3
Yabus VI
Fenti
Surface Condition
Average
Average
Samaa I
Average
Yabus V
Average
Average
Average
Yabus VIII
Block Well
Example of Oil properties in Yabus Formation of Melut basin, DPOC
28

29. y = 26
y = -0.0935x + 143.14
R² = 0.9457
0.0
10.0
20.0
30.0
1150 1200 1250 1300 1350 1400
API
Depth (m)
API Vs Depth of Fal-1&Fal-5
y = -0.1241x + 184.59
R² = 0.946
0.0
10.0
20.0
30.0
1280 1320 1360 1400
API
Depth (m)
API Vs Depth of Fal-3&Fenti
y = -0.036x + 85.636
R² = 0.5786
20.0
30.0
40.0
50.0
1150 1200 1250 1300 1350 1400
PourPoint(℃)
Depth (m)
Pour Point Vs Depth of Fal-1& Fal-5
As the depth is increasing, oil viscosity decreases, API decreases, and pour point decreases
 Low bubble pressure: 300～650psi
 Low GOR: 42.8～89.6scf/bbl
 Medium to heavy oil: oil viscosity 30.4 ～ 360cp;
API 14.5～23.8
 Medium to high pour point: 15.0～42.2℃
1
2
3
29

30. Thank You

31. Special core & PVT Analysis

32. Special Core Analysis (SCAL)

33. A core is a sample of rock in the shape of a cylinder. Taken from the side of a
drilled oil or gas well, a core is then dissected into multiple core plugs, or
small cylindrical samples measuring about 1 inch in diameter and 3 inches
long.
Core Definition
Types of Cores:
There are several types of cores that can be recovered from the well:
Full-diameter cores.
Oriented cores.
Native state cores and
Sidewall cores.
33

34. Core Analysis:
 RCAL
 SCAL
 CCAL
34

35. 35

36. Special Core Analysis:
Detailed understanding of a reservoir requires additional measurements obtained in the special
core analysis laboratory (SCAL). Examples include
ƒ
 Calibrating electrical logging measurements of porosity and saturation.
ƒ
 Determining a formation-specific cutoff value for the relaxation time from a nuclear
magnetic resonance (NMR) log.
ƒ
 Determining capillary pressure measurements to indicate distributions of pore throats and
evaluating saturation distribution as a function of height in a formation.
ƒ
 Relative permeability determines the multiphase flow character of the formation.
 Evaluating wettability.
36

37. Calibrating electrical logging measurements of porosity and saturation
Example of log vs core calibration
37

38. NMR T2 cut-off value:
38

39. Carbonate reservoir Clastic reservoir
Example of T2 cutoff value from NMR log
ƒ
39

40. 40

41. 41

42. 42

43. 43

44. 44

45. Core Acquisition Technique
45

46. 46

47. LAB Technique
47

48. Special Core Analysis (SCAL)
48

49. Routine Core Analysis:
Measurement of basic properties helps you
determine if a rock contains a fluid-filled space
(porosity) and hydrocarbons in that space
(saturation), and the ability of those hydrocarbon
fluids to be produced (permeability). Core gamma
logging links core depth to logging depth.
Computed tomography (CT) scans indicate core
heterogeneity.
49

50. Routine Core Analysis (RCAL)
50

51. Thank You

52. PVT Analysis

53. 53
Main Procedures for PVT laboratory test:
 Flash vaporization.
 Differential vaporization.
 Separator tests.

54. 54
Flash vaporization

55. 55

56. 56

57. 57
Differential vaporization

58. 58

59. 59

60. 60
Separator Test

61. 61

62. THANK YOU

64. 64
 Well performance equations – Darcy's Law.
 Reservoir Pressure Profile.
 Productivity Index Concept.

65. 65

66. 66

67. 67

68. 68

69. 69

70. 70

71. 71

72. 72

73. 73

74. 74

75. 75

76. 76

77. 77
Factors affecting Productivity Index

78. Thank You

79. Reserve Estimation and R.M

80. Reserve Estimation

81. 81
Reserves:
Those quantities of oil and gas
anticipated to be economically
recovery from discovered resources as
reserves.

82. 82
P3
P1 P2

83. 83

84. 84
Types of estimation techniques
Reserves can be estimated by the
followings:
1
2

85. 85
1

86. 86
1

87. 87
1

88. 88
1

89. 89
1

90. 90
The STOIIP of P1, P2, P3 (Proved, Probable, Possible) in each reservoir
is assessed using the volumetric calculation method. The formula is
shown as below.
STOIIP = Ao * H * Por. * So / Boi * 6.29
Where: STOIIP= Original Oil in Place, MMstb
Ao= Oil bearing area (km2)
H = Net pay (m)
Por= Porosity (fraction)
So =Oil saturation (fraction)
Boi= Oil formation factor (v/v)
Volumetric Assessment:
Example of Mirmir area – Melut Basin - DPOC

91. 91
PROVED/PROBABLE/POSSIBLE CATEGORIES
(HALF-WAY CONCEPT)
The categories and halfway concept may be overridden by some other geological,
geophysical and engineering data of which the basis and assumptions must be clearly stated.
Range of Uncertainty Categories for Hydrocarbon Accumulation

92. 92
Based on structure map of pay zones, the boundary line of oil or gas bearing area is
determined by fault boundary, lithology boundary and fluid contacts. Fluid contacts
often are determined by well testing, well logging evaluation and MDT data.
Oil Bearing Area
Net pay for each layer in wells is obtained from well log interpretation. Based on
the net pay contour map, net pay of the hydrocarbon reservoir is determined by
weighting of hydrocarbon bearing area.
Net Pay
Porosity of net pay in wells is obtained from well log interpretation. For a
hydrocarbon reservoir, porosity value is determined by weighting of net pay.
Porosity
Oil saturation of net pay in wells is obtained from well log interpretation. For a
hydrocarbon reservoir, oil saturation value is determined by weighting of net pay.
Oil Saturation
Volume factor is determined based on the PVT data, and obtained from reservoir
engineering analysis.
Formation Volume Factor (Boi)

93. 93
Oil Bearing Area Map of L_Aradeiba-4-2 in Mirmir-1 Block

94. 94

95. 95
2

96. 96
2

97. 97
2

98. 98
2

99. 99
2

100. Thank You

101. Recovery Methods

102. Types of Recovery Methods:
Secondary Recovery
Tertiary Tertiary (EOR)
102
Primary Recovery
Secondary Recovery (IOR)
Tertiary Recovery (EOR)

103. This is the recovery of hydrocarbons from the reservoir using
the natural energy of the reservoir as a drive.
Primary Recovery
(i) Solution gas drive
(ii) Gas cap drive
(iii) Water drive
(iv) Gravity drainage
(v) Combination or mixed drive
103

104. This is recovery aided or driven by the injection of water or
gas from the surface.
Secondary Recovery (IOR)
(i) Waterflooding
(ii) Gasflooding
104

105. Example of secondary drive in Melut basin, DPOC
Year
Productionb/d
105

106. 106
Schematic view of horizontal wells in the water flooding

107. 107

108. 108
Sidetrack to recovery oil in tilted bed

109. 109
Tertiary Recovery / EOR

110. Thermal
Chemical
Miscible gas
110
Tertiary Recovery / EOR

111. 111
Tertiary Recovery / EOR

112. Evaluating grain density, porosity,
permeability, fluid saturations, and more to
optimize production and maximize recovery
112

113. 113

114. 114

115. 115
Production
Time

116. THANK YOU

117. Case study From South Sudan
117

119. Water flooding Reduces Oil Viscosity Well sorting
Large grain Low API
SCAL Formation pressure
Saturation
Single liquid phase
Cubic packing High APIMiscible
1 2 3
4 5 6
7 8 9
10 11 12
119
A

120. Light oil N2
High permeabilityAbove the bubble pointpsi
T2 cut-off48% Porosity
Steam injectionOil gas, or water Oil
Good porosity
Heavy Oil
Secondary recovery
A 120

121. Rock properties Fluid properties
SCAL Drive mechanism
1. ____________________
2. ____________________
3. ____________________
4. ____________________
5. ____________________
6. ____________________
1. ____________________
2. ____________________
3. ____________________
4. ____________________
5. ____________________
6. ____________________
1. ____________________
2. ____________________
3. ____________________
4. ____________________
5. ____________________
6. ____________________
1. ____________________
2. ____________________
3. ____________________
4. ____________________
5. ____________________
6. ____________________
1 2
3 4
B 121

122. 122
Exercises

123. Briefly discus the following:
A. Reservoir pressure
B. Injection well
C. Viscosity
D. Pour point
E. Secondary porosity
F. Wettability
G. Capillary pressure
H. Absolute Open Flow Potential (AOF/AOFP)
I. Computed Tomography (CT)
Exercise 1
123

124. Exercise 2
124

125. Factors affecting PI & IPR ?
Exercise 3
125
1. ………………………………………………………………………………………..
2. ………………………………………………………………………………………..
3. ………………………………………………………………………………………..
4. ………………………………………………………………………………………..
5. ………………………………………………………………………………………..

126. 126
Exercise 4
The STOIIP of P1, P2, P3 (Proved, Probable, Possible) in each reservoir
is assessed using the volumetric calculation method. The formula is
shown as below.
Calculate STOIIP for L_Aradeiba-4-1 Foramation?
STOIIP = Ao * H * Por. * So / Boi * 6.29
Where: STOIIP= Original Oil in Place, MMstb
Ao= Oil bearing area (km2)
H = Net pay (m)
Por= Porosity (fraction)
So =Oil saturation (fraction)
Boi= Oil formation factor (FVF)

127. 127
Oil Bearing Area Map of L_Aradeiba-4-1 in Mirmir N-1 block
Exercise 4

128. 128Exercise 4

129. 129
(A) (B) (C)
EOR Type EOR methods Main Mechanism
1 Thermal Miscible Improve swept efficiency
2 Chemical Hot Water Make oil volumetric swell
3 Gas Injection Gas Injection Viscosity reduction
Exercise 5
Match the following column A, B & C.

131. Quiz
Quiz
Quiz