Chapter5 - CHAPTER 5 CLASSIFICATION OF PETROLEUM RESERVOIRS...

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Unformatted text preview: CHAPTER 5 CLASSIFICATION OF PETROLEUM RESERVOIRS The location of the reservoir temperature relative to the critical temperature of the reservoir fluid can be used to classify the reservoir (fluid) type. • If the reservoir temperature is less than the critical temperature of the reservoir fluid, the reservoir is classified as an oil reservoir. • If the reservoir temperature is greater than the critical temperature of the reservoir fluid, the reservoir is classified as a gas reservoir. • The type of reservoir fluid is normally determined conclusively by a Laboratory PVT Study on a representative sample of the reservoir fluid. See 5- 1 Chapter 10 of McCain for the Lab PVT Study of a Chapter 10 of McCain for the Lab PVT Study of a Black Oil. 5- 2 General Comments on Reservoir Classification • Reservoir pressure and temperature are determined by the depth of the reservoir and are independent of the properties of the reservoir fluid. • The phase behavior of the reservoir fluid is determined by its composition. • Heavy hydrocarbon molecules have high critical temperatures. Therefore, a reservoir fluid that has a high concentration of heavy molecules will have a relatively high critical temperature, which is likely to exceed the reservoir temperature. Such a reservoir will be an oil reservoir. 5- 3 General Comments on Reservoir Classification • Light hydrocarbon molecules have low critical temperatures. Therefore, a reservoir fluid that has a high concentration of light molecules will have a relatively low critical temperature, which is likely to be less than the reservoir temperature. Such a reservoir will be a gas reservoir. • A reservoir fluid that is predominantly methane will have a very low critical temperature similar to that of methane (Tc for methane is –116 °F), which is likely to be considerably less than the reservoir temperature. Such a reservoir will be a dry gas reservoir. 5- 4 Reservoir Pressure Can estimate reservoir pressure for a normally pressured formation as follows: PR = Po + 0.433γ D where PR = reservoir pressure, psia Po = surface pressure at D = 0, psia γ = specific gravity of salt water D = reservoir depth, ft 0.433 = fresh water gradient, psi/ft Example: D γ = = 8000 ft 1.05 Po = 14.7 psia PR = 3652 psia 5- 5 Can also have an overpressured reservoir with PR Can also have an overpressured reservoir with P much higher than for a normally pressured reservoir. 5- 6 Reservoir Temperature Can estimate reservoir temperature using an average geothermal gradient of the area as follows: TR = To + αD where TR = reservoir temperature, °F To = surface temperature at D = 0, °F α D = = geothermal gradient of the area, °F/ft reservoir depth, ft Example: D α = = 8000 ft 0.03 °F/ft for US Gulf Coast To = 75 °F TR = 315 °F 5- 7 The Five Types of Petroleum The Five Types of Petroleum Reservoirs Fluids q Black oil reservoir (Low shrinkage oil). q Volatile oil reservoir (High shrinkage oil or near critical oil). q Retrograde condensate gas reservoir. q Wet gas reservoir. q Dry gas reservoir. 5- 8 Typical Pressure Temperature Typical Pressure Temperature Diagram for a Black Oil Reservoir 5- 9 Black Oil Reservoir General Observations: q Contains a wide range of hydrocarbon molecules from methane to significant amounts of large, heavy, nonvolatile molecules. q Two phase envelop (region) covers a wide temperature range because of the wide range of Tc of the components. q Two phase envelop (region) is the widest of all reservoir fluid types. q Because of the large amounts of heavy molecules, Tc >> TR. 5 - 10 Black Oil Reservoir General Observations: q PR > or = Pb of the oil. q Iso volume lines are uniformly spaced vs pressure, indicating uniform rate of vaporization as pressure is reduced. q Separator and stock tank conditions lie within the two phase region. q Most common type of oil reservoirs. 5 - 11 Black Oil Reservoir Field Observations: q Initial producing gas oil ratio (GOR, Rp) is q typically < 2000 standard cubic feet/stock tank barrel (scf/STB). Producing GOR (Rp) will increase in the future when the reservoir pressure falls below the bubble point pressure. q Initial stock tank oil API Gravity < 45 degrees. ° API = 141.5 − 131.5 γo where γ o is the oil specific gravity at STP. q Stock tank oil API gravity will slightly decrease with time until late in the life of the reservoir when it will increase. q Dark colored liquid in the stock tank. 5 - 12 q Considerable amount of liquid in the stock tank. 5 - 13 Black Oil Reservoir Lab Measurements: q Initial oil formation volume factor (Bo) < 2.0 reservoir barrels/ stock tank barrel (RB/STB). Bo is the reservoir barrels of oil that will yield 1 stock tank barrel of oil. q Concentration of heptanes plus fraction (C7+) in the mixture typically > 30 mole %. Note: By definition, oil shrinkage factor = 1/Bo. Oil with a shrinkage factor slightly less than 1.0 is known as a low shrinkage oil. Oil with a shrinkage factor very much less than 1.0 is known as a high shrinkage oil. 5 - 14 Typical Pressure Temperature Diagram Typical Pressure Temperature Diagram for a Volatile Oil Reservoir 5 - 15 Volatile Oil Reservoir General Observations: q Contains less heavy molecules and more light and intermediates (C1 through C6) than a black oil. q Two phase region covers a smaller temperature range than a black oil because there are less heavy molecules in the mixture. q Because of less heavy molecules and more intermediates, Tc is less than that of a black oil and is only slightly > TR. q TR is close to the Tc of the reservoir fluid. q Critical point is lower on the two phase envelop than for a black oil. 5 - 16 Volatile Oil Reservoir General Observations: q PR > or = Pb of the oil. q Iso volume lines are less evenly spaced vs pressure and more crowded near the bubble point pressure. This indicates a high rate of vaporization below the bubble point as the pressure is reduced. q Separator and stock tank conditions lie within the two phase region. q Less liquid in the stock tank compared to a black oil reservoir for the same reservoir volume because more of the material will vaporize to gas. Hence, the name volatile oil. 5 - 17 Volatile Oil Reservoir Field Observations: q Initial producing gas oil ratio (GOR, Rp) q q typically from 2000 to 3300 standard cubic feet/stock tank barrel (scf/STB) Producing GOR (Rp) will increase in the future when the reservoir pressure falls below the bubble point pressure. Initial oil API Gravity > 40 degrees and increases with time during production because a significant liquid production is due to the condensation of the rich associated gas. q Gases produced below the bubble point are quite rich with intermediates and heavy molecules and behave as retrograde gases. q Amount of liquid condensed from the gas constitutes a significant fraction of the total oil recovery. 5 - 18 q Brown, orange or greenish colored liquid in the stock tank. 5 - 19 Volatile Oil Reservoir Lab Measurements: q Initial oil formation volume factor (Bo) > 2.0 reservoir barrels/ stock tank barrel (RB/STB). q More oil shrinkage than black oil. Should be produced with 3 or 4 stage separation to minimize oil shrinkage and maximize stock oil volume. q Concentration of heptanes plus (C7+) fraction in the mixture typically ranges from 12.5 to 30 mole %. q Heptanes plus concentration (C7+) of 12.5 mole % separates a volatile oil from a retrograde condensate gas reservoir. 5 - 20 Saturated Oil Reservoir with Gas Saturated Oil Reservoir with Gas Cap The oil is at its bubble point. The gas in the gas cap is at its dew point. PR = Pb for the oil. PR = Pd for the gas cap gas. 5 - 21 Pressure Temperature Diagram for Saturated Oil Reservoir with Gas Cap (a) Retrograde cap gas. (b) Nonretrograde cap gas. 5 - 22 Typical Pressure Temperature Diagram for Typical Pressure Temperature Diagram for a Retrograde Condensate Gas Reservoir. 5 - 23 Retrograde Condensate Gas Reservoir General Observations: q Contains less heavy molecules, and more light and intermediates (C1 through C6) than a volatile oil. q Two phase envelop (region) covers a smaller temperature range than a volatile oil as a result. q Because of the high content of light components, Tc << TR. q TR lies between Tc and the cricondentherm. 5 - 24 Retrograde Condensate Gas Reservoir General Observations: q Critical point is lower on the two phase envelop than for a volatile oil. q Separator and stock tank conditions lie within the two phase region. So will condense some liquid at the separator and the stock tank. q Will condense some liquid in the reservoir (retrograde condensation) if the reservoir pressure falls below the upper dew point pressure of the fluid. This is undesirable. 5 - 25 Retrograde Condensate Gas Reservoir Field Observations: q Producing gas oil ratios (GOR, Rp) range from 3300 to 150,000 standard cubic feet/stock tank barrel (scf/STB). q Producing GOR is initially constant until PR falls below the upper Pd and then increases because of liquid condensation in the reservoir. q Initial oil API Gravity between 40 and 60 degrees and increases with time after the reservoir pressure has fallen below the upper dew point pressure. 5 - 26 q Brown, orange, greenish, light or water white colored liquid in the stock tank. 5 - 27 Retrograde Condensate Gas Reservoir Lab Measurements: q Exhibits a dew point at reservoir temperature in PVT experiment. q Concentration of heptanes plus fraction in the mixture is less than 12.5 mole %. q Surface gas is rich in intermediates and should be processed in a gas plant to recover additional liquid. 5 - 28 Equilibrium Shrinkage of Black Oil, Volatile Oil and Retrograde Condensate Liquid 5 - 29 Correlation of Gas Oil Ratio (GOR) versus C7+ Mole% for Retrograde Gas and Oil Reservoirs 5 - 30 Typical Pressure Temperature Typical Pressure Temperature Diagram for a Wet Gas Reservoir. 5 - 31 Wet Gas Reservoir General Observations: q Contains more light and intermediates (C1 through C6) than a retrograde condensate gas. q Two phase envelop (region) covers a smaller temperature range than a retrograde condensate gas as a result. q Because of the high content of light components, Tc << TR and even the cricondentherm is less than TR. 5 - 32 Wet Gas Reservoir General Observations: q Critical point is lower on the two phase envelop than for a retrograde condensate gas. q There is no possibility of liquid condensation in the reservoir. q Separator and stock tank conditions lie within the two phase region. Therefore, some liquid is condensed at the separator and the stock tank. 5 - 33 Wet Gas Reservoir Field Observations: q High producing gas oil ratio (GOR, Rp). Typically > 50,000 scf/STB. q Producing gas oil ratio is constant over time during production because of the constant reservoir fluid composition. q API Gravity between 40 and 60 degrees as in retrograde gas but remains constant with time during production because of the constant reservoir fluid composition. 5 - 34 Wet Gas Reservoir Field Observations: q Water white colored liquid in the stock tank. q It is not easy to distinguish between a wet gas reservoir and a retrograde condensate gas based on oil API gravity and color. Lab Measurements: Exhibits no dew point or bubble point at reservoir temperature in a PVT experiment. Gas Z – factor. 5 - 35 Typical Pressure Temperature Typical Pressure Temperature Diagram for a Dry Gas Reservoir 5 - 36 Dry Gas Reservoir General Observations: q Contains mostly methane with some intermediates (C2 through C6). q Two phase region covers a smaller temperature range than a wet gas as a result. q Because of the high content of methane and light components, Tc << TR and is close to Tc for methane. q Cricondentherm is less than the reservoir temperature. 5 - 37 Dry Gas Reservoir General Observations: q Critical point is lower on the two phase envelop than for a wet gas. q There is no possibility of liquid condensation in the reservoir. q Separator and stock tank conditions lie outside the two phase region. Therefore, there is no liquid condensed at the separator or the stock tank. Field Observations: No hydrocarbon liquid production at surface conditions. Lab Measurements: 5 - 38 Gas Z – factor. Gas Z – factor. 5 - 39 Summary of Reservoir Summary of Reservoir Classification i = initial reservoir conditions r = reservoir conditions after some depletion s = surface or separator conditions 5 - 40 Legend Legend 1i­1r­1s = Undersaturated black oil reservoir 2i­2r­2s = Undersaturated volatile oil reservoir 3i­3r­3s = Retrograde condensate gas reservoir 4i­4r­4s1 = Wet gas reservoir 4i­4r­4s2 = Dry gas reservoir 5 - 41 Summary of Reservoir Classification Summary of Reservoir Classification 5 - 42 Summary of Reservoir Summary of Reservoir Classification Comparison of phase envelops for different hydrocarbon types. 5 - 43 Typical Compositions of Various Typical Compositions of Various Reservoir Fluids Component N2 CO2 C1 C2 C3 iC4 nC4 iC5 nC5 C6 C7+ Total Retrograde Condensate Volatile Black Oil Dry Gas Gas (Mole%) Oil (Mole%) (Mole%) (Mole%) 6.25 2.34 0.29 1.72 0.12 1.50 0.16 0.91 81.13 7.24 79.14 7.48 66.59 5.31 36.47 9.67 0.35 0.09 1.25 0.36 1.76 0.67 3.93 1.44 2.35 0.22 0.03 100.00 3.29 0.51 0.55 0.61 4.80 100.00 4.22 0.85 1.12 1.22 16.64 100.00 6.95 1.44 1.41 4.33 33.29 100.00 5 - 44 5 - 45 ...
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