Production Engineering
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ENG.Ali Yahya Jirjees Reservoir Engineer /Research assistant BSc.H.Dep.MSc.Petroleum engineer/Cairo University
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Production Engineering
- 1. PRODUCTION ENGINEERING PRINCIPLES & PRACTICE E N G . A l i Y a h y a J i r j e e s Reservoir Engineer /Research assistant BSc.H.Dep.MSc.Petroleum engineer/Cairo University E N G . K a r i m M a g d y Power line technical service BSc. Petroleum engineer. suez university
- 2. Course Outlines Well Production Reservoir Production Production Principles Importance Petroleum formation Reservoir Characteristics Primary recovery Secondary recovery Tertiary recovery IPR VLP Pumps
- 3. • Importance • Petroleum Formation • Reservoir characteristics Well Production Reservoir Production Basin AnalysisProduction Principles
- 6. Overview Petroleum formation Maturation&migration Accumulation&Trap Reservoir characteristics
- 7. cooking oil Kerogen Decompo sition Animals Plants Prospects gas Million of Years High temperature High Pressure Petroleum Formation
- 8. Source Maturation Maturation Ro % Model 1cm – 10 MY 1cm–500m
- 16. Reservoir Characteristics • Factors affecting Porosity Pressure temperature Depth Cementing material Sorting packing fractures
- 20. Reservoir Characteristics Permeability and porosity
- 23. Reservoir Characteristics • Surface & Interfacial Tension
- 24. Reservoir Characteristics Oil Formation Volume Factor Bo
- 27. Reservoir Characteristics Gas Oil Ratio GOR
- 28. • Primary Recovery • Secondary Recovery • Tertiary Recovery Well Production Play Analysis Production Principles Reservoir Production
- 29. Primary Recovery
- 30. Primary Recovery Reservoir Production Oil In Place RESERVES
- 32. Primary Recovery Rock Expansion Fluid compressibility Energy Source SlowP decline lowGOR 5%R.F
- 34. Primary Recovery Depletion drive Gas solution expansion Energy Source RapidP decline HighGOR 15%R.F
- 35. Primary Recovery Gas Cap Drive Gas Cap expansion Energy Source MediumP decline Not highGOR 30%R.F
- 37. Primary Recovery Water Drive Water supplement pressure Energy Source steadyP decline noGOR 40%R.F
- 38. Primary Recovery Combination Drive Water & GasEnergy Source mediumP decline lowGOR 30:60%R.F
- 39. Primary Recovery Gravity Drainage Gravity ForceEnergy Source LowP decline lowGOR 50%R.F
- 42. Secondary Recovery • Water Injection Is the process of injection compatible water under pressure into the reservoir to increase oil recovery Injector Producer Water
- 43. Secondary Recovery • Water Injection Assuming that I have a layer of rock that is 300 ft thick, 5 miles wide and 30 miles long , and it has a porosity of 20% ,SO 22.5 billion barrels !!!!!!!
- 44. Secondary Recovery • Water Injection • EA:- Is the fractional area of the pattern that is swept by the displacing fluid. • EV:- Is the fraction of the vertical section of the pay zone that is contacted by injected fluids..
- 45. Secondary Recovery • Water Injection • is the fraction of movable oil that has been displaced from the swept zone at any given time or pore volume injected
- 46. Secondary Recovery • Water Injection • In general, the mobility of any fluid λ is defined as the ratio of the effective permeability of the fluid to the fluid viscosity
- 47. Secondary Recovery • Water Injection • In general, the mobility Ratio is defined as the ratio of the displacing phase mobility the the displaced phase mobility
- 48. Secondary Recovery • Injection Patterns
- 49. Secondary Recovery • Injection Patterns
- 50. Secondary Recovery • Water Injection • For two immiscible fluids, oil and water, the fractional flow of water, fw (or any immiscible displacing fluid), is defined as the water flow rate divided by the total flow rate
- 51. Reservoir Characteristics • Factors affecting Displacement Efficiency Mobility Ratio Viscosity Wettability Interfacial Tension Rate of flow Gravity Force Heterogeneity
- 52. Secondary Recovery • Water Injection when the reservoir pressure reaches its bubble-point pressure
- 53. Fail 25%Unusual Expenses 45%Poor Sweep Efficiency 20%Equipment Failure 5%Others 10%Pattern Secondary Recovery • Major Causes WF Failures
- 54. Secondary Recovery • Reservoir Heterogeneity
- 55. Secondary Recovery Gas Injection Maintain reservoir pressure Decrease oil viscosity so increasing its mobility
- 56. Secondary Recovery Gas Injection Gas injection may be either:- a miscible an immiscible displacement process. Nitrogen gas Injection is rapidly emerging as one of the best enhanced oil and gas recovery methods as it is less expensive and more readily available than natural gas. The injection of carbon dioxide has an even more dramatic effect than hydrocarbon gas on oil viscosity. Also, its swelling tendencies are greater
- 57. Secondary Recovery Reservoir Candidates •No WF •No GIWater drive •Good WF Depletion drive •No WF •No GIGas Cap •Good WF Rock Expansion •No WF •Good GIGravity Drainage
- 61. Tertiary Recovery Mechanisms of Increased Recovery
- 62. Tertiary Recovery Thermal In-Situ Combustion Cyclic Steam Flooding Steam Flooding
- 63. Thermal Recovery Steam Flooding High-temperature steam is continuously injected into a reservoir. As the steam loses heat to the formation, it condenses into hot water, which, coupled with the continuous supply of steam behind it, provides the drive to move the oil to production wells.
- 64. Thermal Recovery Steam Flooding 1. The heated oil becomes less viscous, making it easier to move through the formation toward production wells. 2. Expansion or swelling of the oil aids in releasing it from the reservoir rock. 3. Lighter fractions of the oil tend to vaporize, and as they move ahead into the cooler formation ahead of the steam they condense and form a solvent or miscible bank. 4. Finally, the condensed steam cools as it moves through the reservoir and results in what amounts to an ordinary Water flood ahead of the heated zone.
- 65. Thermal Recovery Cyclic Steam Flooding This method is sometimes applied to heavy-oil reservoirs to boost recovery during the primary production phase.
- 66. Thermal Recovery Cyclic Steam Flooding -A predetermined amount of steam is injected into wells that have been drilled or converted for injection purposes. These wells are then shut in to allow the steam to heat or "soak" the producing formation around the well. - After a sufficient time has elapsed to allow adequate heating, the injection wells are back in production until the heat is dissipated with the produced fluids.
- 67. Thermal Recovery In-Situ Combustion Burning some of the oil in situ (in place), creates a combustion zone that moves through the formation toward production wells, providing a steam drive and an intense gas drive for the recovery of oil.
- 68. Thermal Recovery In-Situ Combustion -This process is sometimes started by lowering a heater or igniter into an injection well. Air is then injected down the well, and the heater is operated until ignition is accomplished. -After heating the surrounding rock, the heater is withdrawn, but air injection is continued to maintain the advancing combustion front. -Water is sometimes injected simultaneously or alternately with air, creating steam which contributes to better heat utilization and reduced air requirements.
- 69. Tertiary Recovery Co2 Flooding Carbon dioxide (CO2) flooding is a process whereby carbon dioxide is injected into an oil reservoir in order to increase output when extracting oil
- 70. Tertiary Recovery Co2 Flooding 1)Miscible CO2 Displacement: Under suitable reservoir pressure and oil density conditions(generally deeper than 1200m with oil lighter 22° API gravity),injected carbon dioxide will mix thoroughly with the oil within the reservoir such that the interfacial tension between these two substances effectively disappears and reduce it’s viscosity. Oil recovery will be from 10 to 15% of OOIP. 2)Immiscible CO2 Displacement: When reservoir pressure is too low and/or oil gravity too dense, the injected CO2 remains physically distinct from the oil within the reservoir. However, injected CO2 still can improve oil recovery by causing the oil to swell, reducing oil's density and improve mobility. But this method isn't efficient.
- 71. • IPR • VLP • Pumps Prospect Evaluation Reservoir Production Production Principles Well Production
- 76. Inflow Performance Straight IPR Determine Flow rate Reservoir Pressure Predict reservoir performance Determine formation damage
- 77. Inflow Performance Straight IPR IPR decreases as Reservoir pressure decrease as a result of production
- 80. Vertical Lift Performance A relationship between flow rate and pressure inside the tubing It depends on:- 1. Tubing size 2. Flow regime inside the tubing 3. GLR
- 81. Artificial Lift
- 82. Artificial Lift