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Enhanced oil recovery basic

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Enhanced Oil Recovery - Basic

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Enhanced oil recovery basic

  1. 1. Jamal S. Peter September - 2019 IOR / EOR - Basic
  2. 2. 2 Introduction Rock & Fluid Properties Special Core & PVT Analysis Reserve Estimation & Recovery Methods Well Performance Analysis Contents :
  3. 3. Introduction 3 A. Improved Oil Recovery (IOR) - mobile oil in the reservoir B. Enhanced Oil Recovery (EOR) - immobile oil
  4. 4. Reservoir Dynamic Properties Production Performance Maximize Recovery Introduction 4
  5. 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. 6. Rock & Fluid Properties
  7. 7. Rock Properties 7
  8. 8. 8
  9. 9. Porosity Permeability Saturation 9
  10. 10. Porosity Permeability Saturation 10
  11. 11. Porosity Permeability Saturation 11
  12. 12. Porosity Permeability Saturation 1 2 3 4 Energy increases 12
  13. 13. Porosity Permeability Saturation 13
  14. 14. Porosity Permeability Saturation 14
  15. 15. Porosity Permeability Saturation 15
  16. 16. Porosity Permeability Saturation 16
  17. 17. Porosity Permeability Saturation 17
  18. 18. Porosity Permeability Saturation 18
  19. 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. 20. Thank You
  21. 21. Fluid Properties
  22. 22. Bubble point pressure Formation Volume Vector Oil Gravity GOR Fluid Properties 22
  23. 23. Oil Gas Water • Estimating properties of reservoir water is important for reservoir calculations, specifically for those with water influx Reservoir fluids 23
  24. 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. 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. 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. 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. 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. 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. 30. Thank You
  31. 31. Special core & PVT Analysis
  32. 32. Special Core Analysis (SCAL)
  33. 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. 34. Core Analysis:  RCAL  SCAL  CCAL 34
  35. 35. 35
  36. 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. 37. Calibrating electrical logging measurements of porosity and saturation Example of log vs core calibration 37
  38. 38. NMR T2 cut-off value: 38
  39. 39. Carbonate reservoir Clastic reservoir Example of T2 cutoff value from NMR log ƒ 39
  40. 40. 40
  41. 41. 41
  42. 42. 42
  43. 43. 43
  44. 44. 44
  45. 45. Core Acquisition Technique 45
  46. 46. 46
  47. 47. LAB Technique 47
  48. 48. Special Core Analysis (SCAL) 48
  49. 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. 50. Routine Core Analysis (RCAL) 50
  51. 51. Thank You
  52. 52. PVT Analysis
  53. 53. 53 Main Procedures for PVT laboratory test:  Flash vaporization.  Differential vaporization.  Separator tests.
  54. 54. 54 Flash vaporization
  55. 55. 55
  56. 56. 56
  57. 57. 57 Differential vaporization
  58. 58. 58
  59. 59. 59
  60. 60. 60 Separator Test
  61. 61. 61
  62. 62. THANK YOU
  63. 63. 64  Well performance equations – Darcy's Law.  Reservoir Pressure Profile.  Productivity Index Concept.
  64. 64. 65
  65. 65. 66
  66. 66. 67
  67. 67. 68
  68. 68. 69
  69. 69. 70
  70. 70. 71
  71. 71. 72
  72. 72. 73
  73. 73. 74
  74. 74. 75
  75. 75. 76
  76. 76. 77 Factors affecting Productivity Index
  77. 77. Thank You
  78. 78. Reserve Estimation and R.M
  79. 79. Reserve Estimation
  80. 80. 81 Reserves: Those quantities of oil and gas anticipated to be economically recovery from discovered resources as reserves.
  81. 81. 82 P3 P1 P2
  82. 82. 83
  83. 83. 84 Types of estimation techniques Reserves can be estimated by the followings: 1 2
  84. 84. 85 1
  85. 85. 86 1
  86. 86. 87 1
  87. 87. 88 1
  88. 88. 89 1
  89. 89. 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
  90. 90. 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
  91. 91. 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)
  92. 92. 93 Oil Bearing Area Map of L_Aradeiba-4-2 in Mirmir-1 Block
  93. 93. 94
  94. 94. 95 2
  95. 95. 96 2
  96. 96. 97 2
  97. 97. 98 2
  98. 98. 99 2
  99. 99. Thank You
  100. 100. Recovery Methods
  101. 101. Types of Recovery Methods: Secondary Recovery Tertiary Tertiary (EOR) 102 Primary Recovery Secondary Recovery (IOR) Tertiary Recovery (EOR)
  102. 102. 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
  103. 103. This is recovery aided or driven by the injection of water or gas from the surface. Secondary Recovery (IOR) (i) Waterflooding (ii) Gasflooding 104
  104. 104. Example of secondary drive in Melut basin, DPOC Year Productionb/d 105
  105. 105. 106 Schematic view of horizontal wells in the water flooding
  106. 106. 107
  107. 107. 108 Sidetrack to recovery oil in tilted bed
  108. 108. 109 Tertiary Recovery / EOR
  109. 109. Thermal Chemical Miscible gas 110 Tertiary Recovery / EOR
  110. 110. 111 Tertiary Recovery / EOR
  111. 111. Evaluating grain density, porosity, permeability, fluid saturations, and more to optimize production and maximize recovery 112
  112. 112. 113
  113. 113. 114
  114. 114. 115 Production Time
  115. 115. THANK YOU
  116. 116. Case study From South Sudan 117
  117. 117. 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
  118. 118. 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
  119. 119. 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
  120. 120. 122 Exercises
  121. 121. 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
  122. 122. Exercise 2 124
  123. 123. Factors affecting PI & IPR ? Exercise 3 125 1. ……………………………………………………………………………………….. 2. ……………………………………………………………………………………….. 3. ……………………………………………………………………………………….. 4. ……………………………………………………………………………………….. 5. ………………………………………………………………………………………..
  124. 124. 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)
  125. 125. 127 Oil Bearing Area Map of L_Aradeiba-4-1 in Mirmir N-1 block Exercise 4
  126. 126. 128Exercise 4
  127. 127. 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.
  128. 128. Quiz Quiz Quiz

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