Bubble point pressure estimation

An oil well is producing 930 scf/STB of 0.742 specific gravity separator gas and 40.8°API stock-tank oil. Separator conditions are 100 psig and 90°F. The well has just been completed reservoir pressure is believed to be above bubble-point pressure. Estimate a value of solution gas oil ratio for use at and above bubble-point pressure. 

The calculation of y and P in Equation 14.16a is achieved by bubble point pressure-type calculations whereas that of x and y in Equation 14.16b is by isothermal-isobaric //cm-/(-type calculations. These calculations have to be performed during each iteration of the minimization procedure using the current estimates of the parameters. Given that both the bubble point and the flash calculations are iterative in nature the overall computational requirements are significant. Furthermore, convergence problems in the thermodynamic calculations could also be encountered when the parameter values are away from their optimal values. 

Although the producing gas-oil ratio data show some scatter, the initial trend is constant. The producing gas-oil ratio will start to increase very soon after bubble-point pressure is reached in the reservoir. Figure 9-2 shows that producing gas-oil ratio starts its increase at about the same cumulative production as the pressure line changes slope. This gives a check on the estimate of bubble-point pressure. 

EXAMPLE 9—1 Estimate bubble-point pressure from the pressure-production history of Figure 9—2. 

The following pressure-production history is available for an oil well. The producing gas-oil ratio is calculated with sales-gas volumes, i.e., stock-tank gas is vented and not measured. The separator operates at 67°F and 100 psig the specific gravity of the separator gas is 0.788, and the gravity of the stock-tank oil is 46.0° API. Estimate the bubble-point pressure and the solution gas-oil ratio at the bubble point for this black oil. Compare your answers with laboratory data which indicate a bubble-point pressure of 1928 psig and a solution gas-oil ratio at the bubble point of 623 scf/STB. 

The pressure-production history for the oil field of Exercise 9-2 is given below. Estimate bubble-point pressure. Compare your answer with laboratory results of 1441 psig. 

This chapter begins with bubble-point pressure and solution gas-oil ratio, and then explains methods of estimating the density of reservoir liquids. The results of the density calculations are used to estimate oil formation volume factors. A technique for adjusting the results of the correlations to fit field derived bubble-point pressure is presented. 

Solution oil and 0.786 specific gravity gas at 768 scf/STB. Producing gas-oil ratio has remained constant, so you believe reservoir pressure is above the bubble-point pressure of the reservoir oil. Estimate bubble-point pressure given that reservoir temperature is 220°F. 

Figure 11-1 also can be used to estimate values of solution gas-oil ratios. Simply enter the right side of the graph with any pressure at or below bubble-point pressure. The result will be solution gas-oil ratio at that pressure. Remember that solution gas-oil ratio is constant above the bubble point. 

EXAMPLE 11- 2 Estimate values of solution gas-oil ratio at various pressures below bubble-point pressure for the reservoir oil of Example 11—1. 

Figure 11-9 may be used to obtain an accurate estimate of formation volume factor of an oil at its bubble point if the producing gas-oil ratio, gas specific gravity, stock-tank oil gravity, and reservoir temperature are known.1,3 Reservoir pressure must be equal to the bubble-point pressure of the oil because the value of gas-oil ratio used to enter the chart must represent the solubility of the gas at the bubble point. If reservoir pressure is below the bubble point, some of the produced gas may come from free gas in the reservoir, and the use of producing gas-oil ratio in this correlation will give incorrect results. 

Estimation of Formation Volume Factor of Oil at Pressures Above the Bubble-Point Pressure... 

The normal procedure for estimating formation volume factor at pressures above the bubble point is first to estimate the factor at bubble-point pressure and reservoir temperature using one of the methods just described. Then, adjust the factor to higher pressure through the use of the coefficient of isothermal compressibility. The equation used for this adjustment follows directly from the definition of the compressibility coefficient at pressures above the bubble point. 

The accuracy of the results of the use of correlations to estimate oil formation volume factor and solution gas-oil ratio can be improved if an accurate value of bubble-point pressure is available. The method described in Chapter 9 can be used to get a reasonably accurate value of bubble-point pressure if reservoir pressure has been measured regularly during the life of the field. 

Figure 11-11 can be used to estimate values of oil compressibility at pressures above the bubble point.6 This is the best available correlation considering both accuracy and ease of use. The results are generally low, by as much as 50 percent at high pressures. Accuracy is improved as bubble-point pressure is approached. 

Estimation of Oil Viscosity at Bubble-Point Pressure and Below... 

A black oil has a bubble-point pressure of 4000 psia at 225°F. The oil formation volume factor at the bubble point is 1.519 res bbl/STB. Estimate the oil formation volume factor at initial reservoir pressure of 6250 psia. Use a value of 13 microsips for the coefficient of isothermal compressibility. 

A black oil has a bubble-point pressure of 1250 psia at reservoir temperature of 142°F. Producing gas-oil ratio is 370 scf/STB of 0.872 specific gravity gas and 40.2°API stock-tank oil. Estimate a value of viscosity at initial reservoir pressure of 2880 psia. 

EXAMPLE 12-6 Estimate the bubble-point pressure of the mixture given in Example 12-1 at a temperature of 150°F. Assume that the equilibrium ratio charts given in Appendix A can be used for this mixture. 

EXAMPLE 16-4 Continue Example 16—1. Estimate the bubble-point pressure of the brine. 

Initial production from a black oil reservoir is 150 STB/d and 10 barrels of water per day. The stock-tank oil is 41.0°API. The produced gas has specific gravity of 0.715. Initial producing gasoil ratio is 1100 scf/STB. Initial reservoir conditions are 7000 psig and 260°F. Bubble-point pressure of the reservoir oil is estimated to be 4850 psia at 260°F. The composition of the produced water is given below. 

Estimation of Formation Volume Factor of Oil at Saturation Pressure Using Ideal-Solution Principles—Estimation of Formation Volume Factor of Oil at Saturation Pressure by Correlation—Estimation of Formation Volume Factor of Oil at Pressures Above the Bubble-Point Pressure Adjustment of Formation Volume Factor of Oil and Solution Gas- Oil Ratio for Field Derived Bubble-Point Pressure Total Formation Volume Factor The Coefficient of Isothermal Compressibility of Oil... 

In the late 1970 s Knapp et al. (1982) performed a very thorough review of VLE for systems of interest in the natural gas processing industry. They summarized their results in terms of the estimate bubble point pressure (AP/P) and the estimate vapor composition (Ay). They reported other errors associated with their predictions, but these are the most significant to this discussion. 

Perhaps the key binary from an acid gas injection point of view is H2S + COz. From the study of Knapp et al. (1982) it can be seen that the PR and SRK equations result in excellent predictions for this binary with errors in the estimated bubble point pressure less than 1.5% and errors in the vapor phase composition less than 1 mol%. 

The dew-point temperature of a gas (vapor) may be found using a method similar to that for bubble-point temperature estimation. Again, suppose a gas phase contains the condensable components A, B. C. .. and a noncondensable component G at a fixed pressure P. Let y/ be the mole fraction of component i in the gas. If the gas mixture is cooled slowly to its dew point, Tdp, it will be in equilibrium with the first liquid that forms. Assuming that Raoult s law applies, the liquid-phase mole fractions may be calculated as... 

At the specified temperature, estimate the bubble point pressure and the equilibrium vapor composition using the K-values based on Raoult s law (Equations 2.18 through 2.20). The liquid composition is the same as the feed composition. 

To find the bubble-point pressure, begin by making an estimate of the bubble pressure and carry out a one-dimensional search for the pressure at which I iKpc = 1 is satisfied to within a tolerance. Make a new chart reading for new K values at each new pressure. The converged pressure is the sought bubble pressure, and the converged y, = Kpci is the mole fraction of the vapor. 

The critical properties for both carbon dioxide and toluene are given in Table 6.6-1. The binary interaction parameter for the COi-toluene mixture is. not given in Table 9,4-1. However, as the value for CO -benzene is 0.077 and that for COi-rt-heptane is 0.10, we estimate that the COi-toluene interaction parameter will be 0.09. Using this value and the bubble point pressure calculation in either the programs or the MATHCAD worksheet for the Peng-Robinson equation of state for mixtures (de.scribed in Appendix B and on the CD-ROM accompanying this book), the following values were obtained ... 

The pressure hold test can be set up as a variant of the bubble point test by using a pressure slightly below the estimated bubble point. It can be set up as a variant of the diffusion test with the pressure around 80% of the bubble point pressure, or it can be set up at lower pressures around 5-10% of the bubble point pressure. The test can be done over a very short period of time or over a protracted hold time. 

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