Pressure bubble-point

Saturation pressure bubble-point pressure) 2620 PSIG 220 F,... 

Gas-Enriched Oils, and of Evaporative Gas-Condensates. It is suggested that the first two regions embrace between them the domain of thermal gas-condensates, insofar as they can be documented by maturity, and of volatile oils often close to their critical points. It is noted in addition that, as shown in Figure 13, oils having saturation pressures (bubble points) greater than 20 MPa also possess elevated values of SF(Pio+), an index of maturity. 

Fig. 2. Trends of fluid pressures versus depth in a West African Tertiary Delta fluid pressures (Pf), saturation pressures (bubble points of oils, Pi, and dew points of gas-condensates, P ). Note the wide scatter around the line of saturation for hydrostatic reservoirs and the extreme under-saturation of some of the oils.

Magnolia Field fluids properties, summarized in Table 1, are strikingly heterogeneous. Figure 5 illustrates this by way of a cross plot of fluid saturation pressure (bubble point and dew point pressures for oil and gas-condensate tests respectively) against measured reservoir pressure for available MDT samples. In very general terms, four fluid types may be defined. Undersaturated oils (solid circles in Fig. 5) are by far the most common. Noteworthy within this family are the two samples that have saturation... 

Pump manufacturers have established guidelines to ensure each pump they supply is not exposed to conditions that result in cavitation. The design standard is called NPSHR or net positive suction head required. The NPSHR takes into account any potential head losses that might occur between the pump s suction nozzle and impeller thereby ensuring the liquid does not drop below its vapour pressure (bubble point). The NPSH is a measure of the proximity of a liquid to its vapour pressure, and must exceed the pump manufacturer s pump NPSHR. There are two process variables that can be adjusted, in case the available NPSH is less than the NPSHR raise the static head and lower friction losses. Conversely, the NPSHR can be reduced by using a larger, slower speed pump, a double suction impeller, a larger impeller inlet area, an oversized pump and a secondary impeller placed ahead of the primary impeller. 

Screen channel LAD performance in high-pressure propellant tanks may be affected by the degree of propellant subcooling and type of gas used during pressurization or liquid expulsion. Therefore it was ensured that bubble point data was collected over the widest possible range of thermal conditions inside a LOX propellant tank, consistent with the limitations of the test hardware. Therefore, the purpose of this chapter is to conduct an in-depth analysis on these high-pressure bubble point tests to understand parameters that affect LAD performance in an elevated pressure environment. 

FIGURE 6.1 Screen/Cup Assembly for High Pressure Bubble Point Experiments. 

Equation fl8.19 means that the available NPSH NPSHj is the difference between the inlet pressure, Pinlet, and P which is the vapor pressure (bubble point pressure for a mixture). It is a system curve for the suction side of a pump. It is required that JVPSH > NPSHji to avoid cavitation. All that remains is to calculate or know the pump inlet conditions in order to determine whether there is enough available NPSH (NPSHjiJto equal or exceed the required NPSH (NPSHj. ... 

The pressure required to force water to enter the pore is called the breakthrough pressure. Bubble point as measured and reported in the literature is the air pressure needed to push out liquid imbibed in the pore of the membrane. The procedure for a bubble point test is described in ASTM Method F-316. The relationship between pore size and bubble point pressure is based on the application of the Young-Laplace equation. The smaller the... 

Transfer the pressure, bubble point, and dew point data to a separate portion of the Worksheet and graph both the bubble and dew points versus pressure. This produces a phase diagram for the hydrocarbon mixture. It should look similar to the following ... 

For bubble-point and dew-point pressure calculations, the appropriate forms are, respectively ... 

The computer subroutines for calculation of vapor-liquid equilibrium separations, including determination of bubble-point and dew-point temperatures and pressures, are described and listed in this Appendix. These are source routines written in American National Standard FORTRAN (FORTRAN IV), ANSI X3.9-1978, and, as such, should be compatible with most computer systems with FORTRAN IV compilers. Approximate storage requirements for these subroutines are given in Appendix J their execution times are strongly dependent on the separations being calculated but can be estimated (CDC 6400) from the times given for the thermodynamic subroutines they call (essentially all computation effort is in these thermodynamic subroutines). 

BUDET calculates the bubble-point temperature or dew-point temperature for a mixture of N components (N < 20) at specified pressure and liquid or vapor composition. The subroutine also furnishes the composition of the incipient vapor or liquid and the vaporization equilibrium ratios. 

Bubble-point and dew-point pressures are calculated using a first-order iteration procedure described by the footnote to Equation (7-25). 

The saturation pressure, P, is different from the bubble point pressure (see. Vidal, 1973) and has no physical reality it merely serves as an intermediate calculation. 

For mixtures, the calculation is more complex because it is necessary to determine the bubble point pressure by calculating the partial fugacities of the components in the two phases at equilibrium. 

Once the bubble point is reached (at point B), the first bubble of ethane vapour is released. From point B to C liquid and gas co-exist in the cell, and the pressure is maintained constant as more of the liquid changes to the gaseous state. The system exhibits infinite compressibility until the last drop of liquid is left In the cell (point C), which is the dew point. Below the dew point pressure only gas remains in the cell, and as pressure is reduced below the dew point, the volume increase is determined by the compressibility of the gas. The gas compressibility is much greater than the liquid compressibility, and hence the change of volume for a given reduction in pressure (the... 

The experiment could be repeated at a number of different temperatures and initial pressures to determine the shape of the two-phase envelope defined by the bubble point line and the dew point line. These two lines meet at the critical point, where it is no longer possible to distinguish between a compressed gas and a liquid. 

When the two components are mixed together (say in a mixture of 10% ethane, 90% n-heptane) the bubble point curve and the dew point curve no longer coincide, and a two-phase envelope appears. Within this two-phase region, a mixture of liquid and gas exist, with both components being present in each phase in proportions dictated by the exact temperature and pressure, i.e. the composition of the liquid and gas phases within the two-phase envelope are not constant. The mixture has its own critical point C g. 

Using this mixture as an example, consider starting at pressure A and isothermally reducing the pressure to point D on the diagram. At point A the mixture exists entirely in the liquid phase. When the pressure drops to point B, the first bubble of gas is evolved, and this will be a bubble of the lighter component, ethane. As the pressure continues to drop, the gas phase will acquire more of the heavier component and hence the liquid volume decreases. At point C, the last drop of liquid remaining will be composed of the heavier component, which itself will vaporise as the dew point is crossed, so that below... 

For both volatile oil and blaok oil the initial reservoir temperature is below the critical point, and the fluid is therefore a liquid in the reservoir. As the pressure drops the bubble point is eventually reached, and the first bubble of gas is released from the liquid. The composition of this gas will be made up of the more volatile components of the mixture. Both volatile oils and black oils will liberate gas in the separators, whose conditions of pressure and temperature are well inside the two-phase envelope. 

A volatile oil contains a relatively large fraction of lighter and intermediate oomponents which vaporise easily. With a small drop in pressure below the bubble point, the relative amount of liquid to gas in the two-phase mixture drops rapidly, as shown in the phase diagram by the wide spacing of the iso-vol lines. At reservoir pressures below the bubble point, gas is released In the reservoir, and Is known as solution gas, since above the bubble point this gas was contained in solution. Some of this liberated gas will flow towards the producing wells, while some will remain in the reservoir and migrate towards the crest of the structure to form a secondary gas cap. 

Black oils are a common category of reservoir fluids, and are similar to volatile oils in behaviour, except that they contain a lower fraction of volatile components and therefore require a much larger pressure drop below the bubble point before significant volumes of gas are released from solution. This is reflected by the position of the iso-vol lines in the phase diagram, where the lines of low liquid percentage are grouped around the dew point line. 

When the pressure of a volatile oil or black oil reservoir is above the bubble point, we refer to the oil as undersaturated. When the pressure is at the bubble point we refer to it as saturated oil, since if any more gas were added to the system it could not be dissolved in the oil. The bubble point is therefore the saturation pressure for the reservoir fluid. 

An oil reservoir which exists at initial conditions with an overlying gas cap must by definition be at the bubble point pressure at the interface between the gas and the oil, the gas-oil-contact (GOC). Gas existing in an initial gas cap is called free gas, while the gas in solution in the oil is called dissolved or solution gas. 

The value of the compresjiibility of oil is a function of the amount of dissolved gas, but is in the order of 10 x 10" psi" By comparison, typical water and gas compressibilities are 4x10" psi" and 500 x 10" psi" respectively. Above the bubble point in an oil reservoir the compressibility of the oil is a major determinant of how the pressure declines for a given change in volume (brought about by a withdrawal of reservoir fluid during production). 

Unlike gases, liquid viscosity decreases as temperature increases, as the molecules move further apart and decrease their internal friction. Like gases, oil viscosity increases as the pressure increases, at least above the bubble point. Below the bubble point, when the solution gas is liberated, oil viscosity increases because the lighter oil components of the oil (which lower the viscosity of oil) are the ones which transfer to the gas phase. 

Assuming an initial reservoir pressure above the bubble point (undersaturated reservoir oil), only one phase exists in the reservoir. The volume of oil (rm or rb) at reservoir conditions of temperature and pressure is calculated from the mapping techniques discussed in Section 5.4. 

As the reservoir pressure drops from the initial reservoir pressure towards the bubble point pressure (PJ, the oil expands slightly according to its compressibility. However, once the pressure of the oil drops below the bubble point, gas is liberated from the oil, and the remaining oil occupies a smaller volume. The gas dissolved in the oil is called the solution gas, and the ratio of the volume gas dissolved per volume of oil is called the solution gas oil ratio (Rg, measured in scf/stb of sm /stm ). Above the bubble point, Rg is constant and is known as the initial solution gas oil ratio (Rgj), but as the pressure falls below the bubble point and solution gas is liberated, Rg decreases. The volume of gas liberated is (Rg - Rg) scf/stb. 

If the reservoir pressure remains above the bubble point then any gas liberated from the oil must be released in the tubing and the separators, and will therefore appear at the surface. In this case the producing gas oil ratio (Rp) will be equal to R. i.e. every stock tank barrel of oil produced liberates Rs scf of gas af surface. 

If, however, the reservoir pressure drops below the bubble point, then gas will be liberated in the reservoir. This liberated gas may flow either towards the producing wells under the hydrodynamic force imposed by the lower pressure at the well, or it may migrate... 

Fluid samples may be collected downhole at near-reservoir conditions, or at surface. Subsurface samples are more expensive to collect, since they require downhole sampling tools, but are more likely to capture a representative sample, since they are targeted at collecting a single phase fluid. A surface sample is inevitably a two phase sample which requires recombining to recreate the reservoir fluid. Both sampling techniques face the same problem of trying to capture a representative sample (i.e. the correct proportion of gas to oil) when the pressure falls below the bubble point. 

Sampling saturated reservoirs with this technique requires special care to attempt to obtain a representative sample, and in any case when the flowing bottom hole pressure is lower than the bubble point, the validity of the sample remains doubtful. Multiple subsurface samples are usually taken by running sample bombs in tandem or performing repeat runs. The samples are checked for consistency by measuring their bubble point pressure at surface temperature. Samples whose bubble point lie within 2% of each other may be sent to the laboratory for PVT analysis. 

The oil and gas samples are taken from the appropriate flowlines of the same separator, whose pressure, temperature and flowrate must be carefully recorded to allow the recombination ratios to be calculated. In addition the pressure and temperature of the stock tank must be recorded to be able to later calculate the shrinkage of oil from the point at which it is sampled and the stock tank. The oil and gas samples are sent separately to the laboratory where they are recombined before PVT analysis is performed. A quality check on the sampling technique is that the bubble point of the recombined sample at the temperature of the separator from which the samples were taken should be equal to the separator pressure. 

Below is a typical oil PVT table which is the result of PVT analysis, and which would be used by the reservoir engineer in calculation of reservoir fluid properties with pressure. The initial reservoir pressure is 6000 psia, and the bubble point pressure of the oil Is 980 psia. 

Reservoir engineers describe the relationship between the volume of fluids produced, the compressibility of the fluids and the reservoir pressure using material balance techniques. This approach treats the reservoir system like a tank, filled with oil, water, gas, and reservoir rock in the appropriate volumes, but without regard to the distribution of the fluids (i.e. the detailed movement of fluids inside the system). Material balance uses the PVT properties of the fluids described in Section 5.2.6, and accounts for the variations of fluid properties with pressure. The technique is firstly useful in predicting how reservoir pressure will respond to production. Secondly, material balance can be used to reduce uncertainty in volumetries by measuring reservoir pressure and cumulative production during the producing phase of the field life. An example of the simplest material balance equation for an oil reservoir above the bubble point will be shown In the next section. 

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