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Line 152: − [[File:Formulae16.png|200px|thumbnail|center]]+ − + + + + − + − For P>Pb: − [[File:Rumus1.png|350px|thumbnail|center]] − + − [[File:Rumus 2.png|350px|thumbnail|center]]+ + + + − − + − [[File:Rumus3.png|210px|thumbnail|center]]+ + + + + − Where, Rsi = saturated gas in oil, Bg formation volume factor gas, and Rs gas saturated under bubble point.+ + − ===<big>Oil Viscosity</big><big></big>===+ − Oil reservoir with pressure above the bubble point, the viscosity decreases as a result of a pressure drop. If otherwise (P <Pb), viscosity enlarged in line with declining reservoir pressure as a result of dissolved gas liberated. + + − For P ≤ Pb:+ − [[File:Rumus4.png|350px|thumbnail|center]]+ − where,+ − [[File:Rumus5.png|200px|thumbnail|center]]+ − + − Live oil calculated by Vasquez-Beggs Corelation: − [[File:Rumus6.png|180px|thumbnail|center]] − Where, μob = viscosity live oil in Pb + + − + + − + − + − [[File:Korelasi 1.png|300px|thumbnail|center]]+ − [[File:Rumus8.png|370px|thumbnail|center]]+ + − + − [[File:Rumus 9.png|250px|thumbnail|center]]+ + − + + + + − [[File:Rumus9.png|370px|thumbnail|center]]+ − − − [[File:Rumus10.png|370px|thumbnail|center]]+ − + + + − *<big>Water Viscosity</big><big></big>+ + + + − Greater reservoir pressure affect the viscosity is getting smaller, the higher the salinity increase water viscosity. The higher temperature causes the viscosity decreases. to determine the viscosity of water McCain correlation can be used.+ − At atmosphere pressure and reservoir temperature:+ − [[File:Rumus11.png|370px|thumbnail|center]] − At reservoir pressure and temperatur : − [[File:Rumus12.png|370px|thumbnail|center]] Line 233:
Line 247: − + − + − Wicaksono. 2015. ''Reservoir Hydrocarbon''. AAPG Short Course: Brawijaya University. − −
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|competition=June 2015
|competition=June 2015
}}
}}
Reservoir rock have many lithologies like sandstones, limestones, granitic, tuff, and shale. Reservoir filled by hydrocarbon on fracture or pores. All reservoir hydrocarbon content connate water . some reservoir content connate water in the micropore that content 10-60% from the pores volume.
Reservoir rock have many lithologies like sandstones, limestones, granitic, tuff, and shale. Reservoir filled by hydrocarbon on [[fracture]] or pores. All reservoir hydrocarbon content connate water . some reservoir content connate water in the micropore that content 10-60% from the pores volume.
Information about scale factor needed to conceptualized reservoir. Scale factor can differences by microscopic; relates to pores and sand grains, macroscopic; relates to conventional core-plug scale, megascopic relates to the scale of grid-blocks in simulation models, and gigascopic relates to regional scale.
Information about scale factor needed to conceptualized reservoir. Scale factor can differences by microscopic; relates to pores and sand grains, macroscopic; relates to conventional core-plug scale, megascopic relates to the scale of grid-blocks in simulation models, and gigascopic relates to regional scale.
===Homogeneity and Heterogeneity===
===Homogeneity and Heterogeneity===
Homogeneity factor consist uniform material. Homogeneity factor is similar depositional environment, grain distribution is relatively similar, and similar kind of intensity diagenesa. While the heterogeneity factors is changes in depositional environment, sedimentary material, grain size distribution, and facies, also different type and intensity of diagenesis processes.
Homogeneity factor consist uniform material. Homogeneity factor is similar depositional environment, grain distribution is relatively similar, and similar kind of intensity diagenesa. While the heterogeneity factors is changes in depositional environment, sedimentary material, [[grain size]] distribution, and facies, also different type and intensity of [[diagenesis]] processes.
===Pore Structure and Geometry===
===Pore Structure and Geometry===
===Reservoir Boundary===
===Reservoir Boundary===
Reservoir bounded by impermeable layers and fluid contact. Field boundaries is ensured through the well but based on well data; electric logs, well flow testing, and repeat formation tester (RFT). Boundary of water and hydrocarbon zones is reduced gradually. This saturation interval resulted in the transition zone. This zone is used as perforation zone in production well.
Reservoir bounded by impermeable layers and [[fluid contacts]]. Field boundaries is ensured through the well but based on well data; electric logs, well flow testing, and repeat formation tester (RFT). Boundary of water and hydrocarbon zones is reduced gradually. This saturation interval resulted in the transition zone. This zone is used as perforation zone in production well.
==Physical Properties of Rocks==
==Physical Properties of Rocks==
Porosity (Phi) 5, permeability (k) mD, fluid saturation (S) %, capiler pressure (Pc) Psi, compressibility (C) Psi^-1, resistivity (R) ohm.
Porosity (Phi) 5, permeability (k) mD, fluid saturation (S) %, capiler pressure (Pc) Psi, compressibility (C) Psi<sup>-1</sup>, resistivity (R) ohm.
===Porosity===
===Porosity===
===<big>Capillary Reservoir Pressure</big><big></big>===
===<big>Capillary Reservoir Pressure</big><big></big>===
Surface pressure of two different types of fluid known as capillary pressure. Capillary pressure is influenced by the pore size and wettability.
Surface pressure of two different types of fluid known as [[capillary pressure]]. Capillary pressure is influenced by the pore size and wettability.
: <math>P_c = \frac{2 \sigma \cos{\theta}}{r}</math>
: <math>P_c = \frac{2 \sigma \cos{\theta}}{r}</math>
With θ wettability contact, σ is surface tension, and r pore size or curvature of the fluid surface. Capillary pressure data known as wetting phase function. Conversion of laboratory data required to determine the reservoir to reservoir capillarity.
With θ wettability contact, σ is surface tension, and r pore size or curvature of the fluid surface. Capillary pressure data known as wetting phase function. Conversion of laboratory data required to determine the reservoir to reservoir capillarity.
: <math>P_{c_{res}} = P_{c_{lab}} \frac{\sigma_{res}(\cos{\theta})_{res}}{\sigma_{lab}(\cos{\theta})_{lab}}</math>
: <math>P_{c_{res}} = P_{c_{lab}} \frac{\sigma_{res}(\cos{\theta})_{res}}{\sigma_{lab}(\cos{\theta})_{lab}}</math>
If the hydrocarbon pressure equal to the water capillary pressure equal with zero. This point is called as a free water level (FWL).
If the hydrocarbon pressure equal to the water capillary pressure equal with zero. This point is called as a [[free water level]] (FWL).
: <math>\text{P}_\text{c} = \text{P}_\text{hc} - \text{P}_\text{w}</math>
: <math>\text{P}_\text{c} = \text{P}_\text{hc} - \text{P}_\text{w}</math>
Changes in capillary pressure against the reference position below the hydrocarbon zone can be seen as a function of:
Changes in capillary pressure against the reference position below the hydrocarbon zone can be seen as a function of:
: <math>C_f = \frac{0.853531}{(1 + 2.47664 \times \phi)^{0.92990}}</math>
: <math>C_f = \frac{0.853531}{(1 + 2.47664 \times \phi)^{0.92990}}</math>
For hydrocarbon reservoir compressibility can be express by:
For [[hydrocarbon reservoir]] compressibility can be express by:
:<math>\text{C}_\text{t} = \text{S}_\text{o} \text{C}_\text{o} + \text{S}_\text{g} \text{C}_\text{g} + \text{S}_\text{w} \text{C}_\text{w} + \text{C}_\text{f}</math>
:<math>\text{C}_\text{t} = \text{S}_\text{o} \text{C}_\text{o} + \text{S}_\text{g} \text{C}_\text{g} + \text{S}_\text{w} \text{C}_\text{w} + \text{C}_\text{f}</math>
===Specific Gravity===
===Specific Gravity===
Specific gravity defined by the rate of gas density in a pressure and temperature sub surface by gas density in equal temperature and pressure (usually in surface). </ref><ref name=Wicaksono2015> Wicaksono. 2015. ''Reservoir Hydrocarbon''. AAPG Short Course: Brawijaya University.</ref>
Specific [[gravity]] defined by the rate of gas density in a pressure and temperature sub surface by gas density in equal temperature and pressure (usually in surface). </ref><ref name=Wicaksono2015> Wicaksono. 2015. ''Reservoir Hydrocarbon''. AAPG Short Course: Brawijaya University.</ref>
: <math>\gamma_g = \frac{MW}{28.97}</math>
: <math>\gamma_g = \frac{MW}{28.97}</math>
For P ≤ P<sub>b</sub>, use Standing correlation:
For P ≤ P<sub>b</sub>, use Standing correlation:
: <math>B_o = 0.972 + 0.000147 F^{1.175}</math>
T in Fahrenheit (°F)
Where
: <math>F = R_s \left ( \frac{\gamma_g}{\gamma_o} \right )^{0.5} + 1.25T</math>
with T in Fahrenheit (°F)
===<big>Compressibility Oil</big><big></big>===
===Compressibility Oil===
If there is no PVT analysis data, compressibility oil can be calculated by this equation
If there is no PVT analysis data, compressibility oil can be calculated by this equation
For P<Pb:
For P > P<sub>b</sub>:
: <math>C_o = \frac{5Rsb + 1.72T - 1180 \gamma_g + 12.62 ^{\circ}\text{API} - 1433}{P \times 10^5}</math>
For P < P<sub>b</sub>:
: <math>\ln{C_o} = -0.644 - 1.430 \ln{P} - 0.395 \ln{P_b} + 0.390 \ln{T} + 0.455 \ln{Rsb} + 0.262 \ln(^{\circ} \text{API})</math>
Where T in Fahrenheit (°F)
Where T in Fahrenheit (°F)
===<big>Formation Volume Factor of two Phase</big><big></big>===
===<big>Formation Volume Factor of two Phase</big><big></big>===
Above bubble point pressure, gas and oil combined in one phase. For this case, fluid volume in reservoir have different value in surface volume, and it is called two-phase formation volume factor (Bt), expressed by :
Above bubble point pressure, gas and oil combined in one phase. For this case, fluid volume in reservoir have different value in surface volume, and it is called two-phase formation volume factor (B<sub>t</sub>), expressed by:
: <math>B_t = B_o + B_g (R_{s_i} + R_s)</math>
Where,
* R<sub>s<sub>i</sub></sub> = saturated gas in oil,
* B<sub>g</sub> = formation volume factor gas, and
* R<sub>s</sub> = gas saturated under bubble point
===Oil Viscosity===
Oil reservoir with pressure above the bubble point, the viscosity decreases as a result of a pressure drop. If otherwise (P <Pb), viscosity enlarged in line with declining reservoir pressure as a result of dissolved gas liberated.
'''For P ≤ P<sub>b</sub>:'''
Dead oil calculated by Egbogah correlation:
: <math>\log [ \log(\mu_{OD} + 1)] = 1.8653 - 0.025086(^{\circ} \text{API}) - 0.5644 \log{T}</math>
Live oil calculated by Beggs-Robinson correlation:
: <math>\mu_o = 10.715 (R_s + 100)^{0.515} \mu_{OD}^B</math>
where,
: <math>B = 5.44 (R_s + 150)^{-0.388}</math>
For P> Pb,
'''For P > P<sub>b</sub>:'''
Live oil calculated by Vasquez-Beggs Corelation:
: <math>\mu_o = \mu_{ob} \left ( \frac{P}{P_b} \right )^m</math>
[[File:Rumus7.png|350px|thumbnail|center]]
Where μ<sub>ob</sub> = viscosity live oil in Pb
: <math>m = 2.6P^{1.187} \exp [-11.513 - 8.98 \times 10^{-5} \times P]</math>
==Physical Properties Water Formation==
==Physical Properties Water Formation==
===<big>Water Formation Volume Factor</big> <big></big>===
===Water Formation Volume Factor===
Water formation volume factor (Bw) estimated by McCain correlation:
Water formation volume factor (B<sub>w</sub>) estimated by McCain correlation:
: <math>B_w = (1 + \Delta V_{WT}) (1 + \Delta V_{WP})</math>
Where,
Where,
: <math>\Delta V_{WT} = -1.0001 \times 10^{-2} + 1.33391 \times 10^{-4T} + 50.50654 \times 10^{-7} T^2</math>
: <math>\Delta V_{WP} = -1.95301 \; \times \; 10^{-9} PT \; - \;1.72834 \; \times \; 10^{-13} P^2 T \; - \; 3.58922 \; \times \; 10^{-7} P \; - \; 2.25341 \; \times \; 10^{-10} P^2</math>
===<big>Saturated Gas in Water</big><big></big>===
===Saturated Gas in Water===
The gas can be dissolved in water formation, the factors that influence it is salinity. Estimated solubility is calculated by correlation McCain:
The gas can be dissolved in water formation, the factors that influence it is salinity. Estimated solubility is calculated by correlation McCain:
: <math>Rsw = Rswp \times 10^{-0.0840655 S \times T^{-0.285854}}</math>
Rswp is saturated gas in pure water:
Rswp is saturated gas in pure water:
<math>\text{R}_\text{swp} = \text{A} + \text{BP} + {\text{CP}^2}</math>
: <math>\text{R}_\text{swp} = \text{A} + \text{BP} + {\text{CP}^2}</math>
Where,
Where,
: <math>\text{A} = 8.15839 - 6.12265 \times 10^{-2} \text{T } + 1.91663 \times 10^{-4} \text{T}^2 - 2.1654 \text{T}^3</math>
: <math>\text{B} = 1.01011 \; \times \; 10^{-2} \; - \; 7.44241 \; \times \; 10^{-5} \text{T } + \; 3.05553 \; \times \; 10^{-7} \text{T}^2 \; - \; 2.94883 \; \times \; 10^{-10} \text{T}^3</math>
: <math>\text{C} = 10^{-7} (9.02505 \; - \; 0.130237 \text{T } + \; 8.53425 \; \times \; 10^{-4} \text{T}^2 \; - \; 2.34122 \; \times \; 10^{-6} \text{T}^3 \; + \; 2.37049 \; \times \; 10^{-9} \text{T}^4)</math>
===Water Compressibility===
===<big>Water Compressibility</big><big></big>===
Compressibility can be calculated by Osif correlation at pressure above the pressure Pb in water and gas systems.
Compressibility can be calculated by Osif correlation at pressure above the pressure Pb in water and gas systems.
: <math>C_w = - \frac{1}{Bw} \left ( \frac{\partial Bw}{\partial P} \right )_T</math>
: <math>C_w = (7.033P + 541C_{NaCl} - 537.0T + 403.300)^{-1}</math>
Where CNaCl is water salinity
Where CNaCl is water salinity
===Water Viscosity===
Greater reservoir pressure affect the viscosity is getting smaller, the higher the salinity increase water viscosity. The higher temperature causes the viscosity decreases. to determine the viscosity of water McCain correlation can be used.
At atmosphere pressure and reservoir temperature:
: <math>\mu_{w1} = (109.574 - 8.40564S + 0.313314S^2 + 8.72213 \times 10^{-5} S^3) \times T^A</math>
where
: <math>A = -1.2166 \; + \; 2.63951 \; \times \; 10^{-2} S \; - \; 6.79461 \; \times \; 10^{-4} S^2 \; - \; 5.47119 \; \times \; 10^{-5}S^3 \; + \; 1.55586 \; \times \; 10^{-6}S^4</math>
At reservoir pressure and temperature:
: <math>\mu_w = (0.9994 + 4.0295 \times 10^{-5} P + 3.1062 \times 10^{-9} P^2) \times \mu_{w1}</math>
==References==
==References==
{{reflist}}
{{reflist}}
==Source==
==Other Source==
* Koesoemadinata. 1980. ''Geologi Minyak dan Gas Bumi''. Bandung: ITB
Koesoemadinata. 1980. ''Geologi Minyak dan Gas Bumi''. Bandung: ITB