Fluid Properties Review PETR 318 Reservoir Engineering

Fluid Properties Review.doc PETR 318 RESERVOIR ENGINEERING HOMEWORK 2 Due on Tuesday Jan 26, 2016 Experiments were made on a bottom-hole crude oil sample taken

Experiments were made on a bottom-hole crude oil sample taken from the North Grieve Field to determine the gas solubility and oil formation volume factor as a function of pressure. The initial reservoir pressure was recorded as 3600 psia and reservoir temperature was 130°F. The following data were obtained from the measurements: Pressure Rs Bo psia scf/STB bbl/STB .........070 At the end of the experiments, the API gravity of the oil was measured as 40°. If the average specific gravity of the solution gas is 0.7. Answer the following questions: a. What factors affect the solubility of gas in crude oil? b. Plot the solution gas ratio versus pressure. c. Was the reservoir initially saturated or undersaturated? Explain. d. Does the reservoir have an initial gas cap? e. In the region of 200 to 2500 psia, determine the solubility of the gas from your graph in scf/STB/psi. f. Suppose 1000 scf of gas had accumulated with each stock tank barrel of oil in the reservoir instead of 567 scf. Estimate how much gas would have been in solution at 3600 psia. Would the reservoir oil then be called saturated or undersaturated? Write a 4-5 paged double spaced reading response on the biography of ONE African leader based on Wilson, Lindy, Bereket Habte Selassie, Georges-Nzongola-Ntalaja, and Ernest Harsch.2015.

Sample Paper For Above instruction

Understanding the behavior of gas solubility in crude oil is fundamental in reservoir engineering because it influences recovery strategies, pressure management, and production forecasts. The factors affecting gas solubility are numerous and interconnected. These include pressure, temperature, oil composition, and the presence of other gases or impurities. An increase in pressure generally increases gas solubility due to Henry's law, which states that the amount of gas dissolved in a liquid is proportional to the partial pressure of the gas above the liquid. Temperature plays an inverse role; higher temperatures tend to decrease gas solubility, as gases are less soluble in hotter liquids. The composition of the crude oil itself, especially its API gravity and specific gravity, influences how much gas can dissolve—lighter oils tend to dissolve less gas compared to heavier oils. Additionally, the presence of other gases, such as lighter hydrocarbons or non-hydrocarbon gases, can alter the solubility equilibrium by changing the gas mixture's partial pressures and interactions.

Plotting the solution gas ratio (Rs) versus pressure provides a visual understanding of the gas-in-oil system. As pressure increases from a low base, Rs generally rises sharply at first, reflecting increased solubility as the gas pressure approaches equilibrium with the oil. The graph typically exhibits a nonlinear trend: initially steep, then gradually leveling off as the solubility reaches a maximum at the bubble point pressure. In the context of the North Grieve field data, the measured Rs values at different pressures allow us to identify the bubble point, which is the pressure at which the oil becomes saturated with gas and free gas begins to form. Determining whether the reservoir was initially saturated or undersaturated hinges on whether the initial pressure was above or below this bubble point. Since initial reservoir pressure was 3600 psia, assuming the graph and data show Rs values consistent with a pressure above the bubble point, the reservoir was initially saturated; otherwise, it was undersaturated.

Regarding the existence of an initial gas cap, it depends on the presence of free gas at original reservoir conditions. If the initial volume of free gas measured at reservoir conditions indicates a significant free gas zone, then a gas cap was present. If the initial Rs values and pressure point to a predominantly dissolved gas phase without free gas, then no initial gas cap existed.

From the experimental data, specifically in the pressure range of 200 to 2500 psia, the solubility of gas can be interpolated from the Rs versus pressure curve. This involves drawing the graph and identifying RS values corresponding to the pressure range of interest, then calculating the gas in solution per stock tank barrel (STB). The solubility is expressed as scf/STB/psi, which indicates the volume of gas in solution per barrel per psi of pressure differential. Such calculations are vital for understanding reservoir behavior over a broad pressure range and aid in planning production strategies.

Suppose a hypothetical scenario where 1000 scf of gas was accumulated per barrel instead of the original 567 scf. This indicates a higher in-situ gas volume in the reservoir, which would likely alter the initial conditions. Estimating the amount of gas in solution at 3600 psia under this scenario involves understanding how the increased gas volume impacts the solubility and saturation status. Greater in-situ gas volume suggests that the oil was initially more saturated, possibly leading to a free gas zone or gas cap. If the gas volume exceeds the solubility limit, the reservoir would be classified as saturated; if not, it remains undersaturated. These insights are crucial for accurate reservoir modeling and prediction of deliverability during production.

In conclusion, the examination of gas solubility factors, the analysis of solution gas ratio versus pressure, and the hypothetical adjustments to gas accumulation underscore the complex interplay of thermodynamics and fluid interactions in reservoir engineering. Proper interpretation of such data informs effective reservoir management, ensuring optimized hydrocarbon recovery while maintaining reservoir integrity.

References

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