JNTU
JNTU B.Tech III PETROLEUM RESERVOIR ENGINEERING Previous Question Paper (November/December - 2020 - R16)
Answer any five questions. All questions carry equal marks.
Main
An oil reservoir exists at its bubble-point pressure of 3,000 psia and temperature of 160°F. The oil has an API gravity of 42° and gas-oil ratio of 600 scf/STB. The specific gravity of the solution gas is 0.65. The following additional data are also available: Reservoir area = 640 acres, Average thickness = 10 ft, Connate water saturation = 0.25, oil formation volume factor (β0) = 1.396 bbl/STB, Effective porosity = 15%. Calculate the initial oil in place in STB.
Answer
The initial oil in place (N) is calculated using the volumetric formula for a reservoir at its bubble-point pressure:
Given the parameters:
- Reservoir Area (A) = 640 acres
- Average Thickness (h) = 10 ft
- Effective Porosity (φ) = 0.15
- Connate Water Saturation (Sw) = 0.25
- Oil Formation Volume Factor (Bo) = 1.396 bbl/STB
Substituting the values into the equation:
The initial oil in place is approximately 4,001,261 STB.
Explain how producing gas-oil ratio varies with average reservoir pressure for a typical solution gas drive with a schematic.
Answer
In a solution gas drive reservoir, the producing gas-oil ratio (GOR) is primarily governed by the liberation of dissolved gas from the oil as reservoir pressure drops below the bubble point pressure. The behavior of the GOR as a function of average reservoir pressure can be divided into three distinct stages.
1. Above Bubble Point Pressure: When the reservoir pressure is above the bubble point, the oil is undersaturated. No free gas exists in the reservoir, and the produced GOR remains constant and equal to the initial solution gas-oil ratio (Rs). The gas produced is only that which is dissolved in the oil at the surface.
2. Below Bubble Point Pressure: As the pressure falls below the bubble point, gas begins to evolve from the oil within the reservoir. Initially, this gas remains trapped as immobile bubbles. As the pressure continues to decline, the gas saturation increases until it reaches the critical gas saturation. During this phase, the produced GOR remains relatively low, though it begins to rise slightly as the gas saturation approaches the critical threshold.
3. Beyond Critical Gas Saturation: Once the gas saturation exceeds the critical gas saturation, the gas becomes mobile and flows toward the wellbore along with the oil. Because gas has a much lower viscosity than oil, its relative permeability increases rapidly as gas saturation rises. Consequently, the produced GOR increases dramatically as the reservoir pressure continues to decline, eventually peaking as the reservoir pressure approaches abandonment levels.
What is effective and relative permeability? Discuss the two phase relative permeability curve for water-oil system.
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Derive the basic radial diffusivity equation.
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The following data are available on a well in the Red River Field: Pe = 2506 psi, Pwf = 1800 psi, re = 745ft, rw = 0.25 ft, Bo = 1.25, μo = 2.5cp, co = 25 × 10-6 psi-1, k = 0.12 Darcy h = 25 ft. Assuming steady-state, calculate the oil flow rate.
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Show that the radial form of Darcy’s equation is the solution to diffusivity equation for radial flow.
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The data in the table were recorded during a constant rate pressure drawdown test. Known reservoir data are: wellbore radius (rw) = 0.198 ft, total compressibility (ct) = 17 × 10-7 psi-1, production rate (Qo) = 250 STB/D, thickness (h) = 69 ft, viscosity (μo) = 0.8 cp, porosity (φ) = 0.039, OFVF (Bo) = 1.136 bbl/STB. The tubing area is 0.0218 sq ft; the density in the wellbore is 53 lbm/cu ft. Determine:
Average formation permeability.
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Skin factor.
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A well is producing under a constant flow rate. To analyze the damage, the well is shut-in for a buildup test. The cumulative oil production from the well at shut-in is 13,220 STB. Well and reservoir data are as given: Porosity φ = 17%, Viscosity μ = 0.6 cp, Total compressibility Ct = 18 × 10-6 psi-1, Drainage radius re = 1320 ft, Wellbore radius rw = 0.5 ft, OFVF B0 = 1.214 bbl/STB, Reservoir thickness h = 28 ft and Flow rate before shut-in q = 1135 STB/day. Estimate the reservoir permeability and Determine whether the well is damaged or stimulated.
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A gas well is producing at a constant rate of 7454.2 Mscf/day under transient flow conditions. The data available are: k= 50 md, h= 10 ft, φ= 20%, Pi= 1600 psi, T= 600° R, rw= 0.3ft, cti= 6.25 × 10-4 psi-1, skin (s)= 1.732, non-Darcy flow coefficient (F)= 0.14 psi2/cp/(Mscf/day)2. Calculate the bottom hole flowing pressure after 4 hours.
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