How do you determine the bubble point pressure of a reservoir fluid? This is a common question in the oil and gas industry, as it affects the phase behavior, composition, and recovery of hydrocarbons from the reservoir. In this article, you will learn what the bubble point pressure is, why it is important, and how to estimate it using different methods.
The bubble point pressure is the pressure at which the first bubble of gas appears in a liquid hydrocarbon mixture at a given temperature. It is also the pressure at which the liquid and gas phases are in equilibrium, meaning that they have the same composition and fugacity. The bubble point pressure is a function of the temperature and the composition of the reservoir fluid, and it varies for different fluid types, such as black oil, volatile oil, or gas condensate.
Experimentally taking the fluid samples (PVT) data to get the bubble point pressure. Or using correlations such as : Standing-Katz Chart or Standing's Correlation.
Presión a la cual el crudo líquido libera la primera burbuja de gas previamente disuelto en él. Se denota como: Pb, también se le conoce cómo Presión de Saturación.
In my experience bubble point is more faster done on clear oil and it’s very important to be done on the product of hydrocarbons for safety reasons.
Una de las importancias del uso de los completamientos inteligentes es el monitoreo de los parámetros de producción en tiempo real para evitar llegar al punto de burbuja del yacimiento.
Boiling point: when a liquid got to turn into gas , due to a higher temperature and pressure.
The bubble point pressure is important because it determines the phase behavior of the reservoir fluid during production. If the reservoir pressure is above the bubble point pressure, the fluid will remain in a single liquid phase, and its properties will change slightly with pressure. However, if the reservoir pressure drops below the bubble point pressure, the fluid will split into a liquid and a gas phase, and its properties will change significantly with pressure. This affects the flow behavior, compressibility, viscosity, density, and saturation of the fluid, as well as the recovery factor and the reservoir performance.
Because it determines when the reservoir transitions from a single or two phase state to a three phase (+gas) state, see, for instance Lake 87. Note that when this happens depends on the pore structure of the reservoir rock, determining the local capillary pressure. Thus, the process starts in the rocks with the largest pores or within fractures and voids, gradually spreading into finer grained facies.
It's a crucial property for the reservoir. Because it determines the reservoir energy and drive mechanism. Also determine the reservoir type and estimate productivity through the production performance .
The appearance of the gas phase happens when the pressure becomes lower than the bubble pressure at the reservoir temperature. Gas bubbles will occupy pore spaces, at a saturation below the minimum requierd to flow due to capillary pressure. The inmobile gas will be an obstacle for the oil flow: the relative permeability to oil being lower than the total permeability. Further descent in pressure will result in increase in gas saturation to a point when it will flow. The oil phase permeability will still be lower, the oil viscosity will increase as it looses gas; both effects are against the flow of oil. Then the reservoir will loose gas, which means a descent of its energy. Therefore oil reserves may decrease at pressure below bubble point.
El control de la presión de fondo fluyente por encima de la presión de burbuja en yacimientos subsaturados resulta vital en el ciclo de vida productiva del pozo y en la mayor recuperación de reserva posible. La toma de decisiones oportuna en superficie para su control define la optimización de este ciclo de vida. La importancia de entender el comportamiento de los fluidos es primordial para que los proyectos sean rentables. A nivel de yacimiento esto se traducira? en utilizar eficientemente la energi?a natural del mismo para maximizar la extraccio?n de la reserva. Mientras que, a nivel superficial, el adecuado dimensionamiento de las instalaciones y la ma?xima recuperacio?n de li?quidos sera?n el resultado de este entendimiento.
The bubble point pressure plays a significant role in estimating reservoir productivity and designing production strategies. In an undersaturated reservoir, maintaining the pressure above the bubble point can lead to higher oil production rates and better recovery efficiency. Additionally, understanding how the bubble point relates to the reservoir's pressure and temperature conditions can help in optimizing well completions and production operations to maximize output.
One way to estimate the bubble point pressure of a reservoir fluid is to use empirical correlations that relate it to other fluid properties, such as specific gravity, molecular weight, or solution gas-oil ratio. These correlations are based on experimental data from different reservoirs and fluid types, and they have different ranges of applicability and accuracy. Some examples of commonly used correlations are the Standing, Vasquez-Beggs, Glaso, Al-Marhoun, and Petrosky-Farshad correlations. To use these correlations, you need to know the temperature and the composition of the reservoir fluid, and then apply the appropriate formula or graph to calculate the bubble point pressure.
McCain et al. (in their book “Petroleum Reservoir Fluid Property Correlations”) compared the accuracy of several correlations available for Pb estimation. Some of their interesting findings: ? They proposed Valko-McCain (2003) correlation as the best correlation. (doi: 10.1016/S0920-4105(02)00319-4.) ? Regarding the correlations more popular in the industry, Standing and Lasater showed better prediction results. ? The average absolute relative errors are approximately the same for different geographical datasets. They concluded that regional correlations are not necessary for Pb.
En la Literatura existen diversas correlaciones para las distintas propiedades PVT, entre ellas la Presión de burbuja (Pb). Casi todas requieren la misma data, pero los resultados no son necesariamente similares, dado que estas son ecuaciones empíricas desarrolladas para adaptaciones a condiciones específicas. Lo recomendable es contar con data real de campo (un análisis PVT) que permita determinación de un valor de Pb real de un yacimiento y compara estas correlaciones con este valor. También es recomendable conocer los rangos de aplicación de las correlaciones
Another way to estimate the bubble point pressure of a reservoir fluid is to perform a pressure-volume-temperature (PVT) analysis, which is a laboratory test that measures the physical and thermodynamic properties of the fluid at different pressures and temperatures. A PVT analysis can provide more accurate and reliable results than correlations, as it accounts for the specific characteristics of the fluid and the reservoir conditions. A PVT analysis involves taking a fluid sample from the reservoir, flashing it to atmospheric conditions, recombining it to its original composition, and then subjecting it to a series of steps that simulate the production process. By measuring the volume, pressure, temperature, and composition of the liquid and gas phases at each step, you can determine the bubble point pressure of the fluid.
PVT application for the estimation of bubble point pressure is an effective means that doesn't only give the variables but also helps describe the properties of the fluid as a result of the changes in variables such as pressure, temperature, and volume.
During the PVT test, the fluid is driven to a repeatable equilibrium end-point condition through agitation or stirring. In a coreflood experiment with depressurization, the fluid isn’t agitated or stirred. As a result, with some live oils, it is possible during a coreflood test for gas to stay in solution for some time when pressure is somewhat below the PVT-defined bubble point pressure. This condition contributes to experimental mis-interpretation of critical gas saturation, relationship between critical gas saturation and depressurization rate, and fluid saturations after depressurization steps.
Exactly from the plot of a relative volume versus pressure by conducting a CCE test You can read the bubble pressure directly from the plot where the relative volume equals to 1.
While PVT analysis is a powerful tool for estimating bubble point pressure, the accuracy of the results heavily depends on the integrity of the fluid sample from the point of sampling to analysis in the lab. Use of downhole sampling and maintaining reservoir conditions during sampling and transport can mitigate these errors. If the sample has flashed, recombination experiments based on separator gas and liquid can be used to recreate the reservoir fluid for PVT analysis. Rigorous quality control in laboratory procedures is necessary to ensure the reliability of the results. This includes cross-checking with other reservoir data when possible.
El análisis PVT tiene varias pruebas, concretamente para efectos de la determinación de la presión de burbuja (Pb) se utiliza la Liberación Instantánea. En este caso se tiene la muestra a una determinada presión superior al valor de Pb (masa en estado totalmente líquido). Se determina el volumen de la muestra. Se hacen sucesivas disminuciones de presión, y se registran los volúmenes en cada caso, se procede a graficar Presión vs Volumen, y el valor de presión donde se observa el cambio de pendiente corresponde al valor de Pb. Existe una función (denominada función Y) que se utiliza para corregir este valor, en caso de sobreestimación o subestimación del valor de Pb, y utiliza los mismos datos del análisis
A third way to estimate the bubble point pressure of a reservoir fluid is to use simulation software that can model the phase behavior and the properties of the fluid using equations of state (EOS). An EOS is a mathematical expression that relates the pressure, volume, temperature, and composition of a fluid, and it can predict the bubble point pressure and other phase envelopes of the fluid. To use simulation software, you need to input the temperature and the composition of the reservoir fluid, and then select an EOS that best fits the fluid type and the reservoir conditions. Some examples of simulation software that can estimate the bubble point pressure are PVTsim, WinProp, and CMG.
The saturation pressure can be estimated by going through the below steps. - Split up the plus fraction in carbon number fractions. - Assign a critical temperature, a critical pressure and an acentric factor to each component and carbon number fraction. - Use an equation of state (Soave-Redlich-Kwong or Peng-Robinsen) to estimate the saturation pressure. Several commercial PVT software packages exist that can carry out the above steps.
Reservoir fluids, a complex mix of organic molecules, undergo a detailed analysis called crude assay. This assessment yields crucial data on properties. Using a simulation package, we model the bubble point based on reservoir pressure and temperature for enhanced reservoir understanding in petroleum engineering.
Los softwares de simulación utilizan mayormente 2 modelos de fluidos: el de petróleo negro (correlaciones PVT) o el composicional (ecuaciones de estado). Los de petróleo negro requerirían conocer que correlación aplica en el caso a simular, en tanto que el composicional requiere un análisis cromatográfico a fin de determinar la envolvente de fases en base a ecuaciones de estado, igualmente se recomienda contar con al menos un dato real de Pb para corroboración. Por supuesto, diferentes simuladores hacen diferentes procesos, simuladores como Hysys y ProII se especializan en Procesos, y son ideales para estos cálculos, pero software como Pipesim, Wellflo y Prosper también tienen la capacidad de hacer tal cálculo
Unusual increase in Gas Oil Ratio of a well may be a good indication that it may have started to flow below its bubble point pressure. This could be verified by carefully reviewing downhole pressure data if such a system has been installed or it could be confirmed by running downhole pressure survey. Wellbore damage is the main reason of FBHP falling below BPP. If wells equipped with downhole ESPs flow below BPP, the pump may cavitate due to presence of excessive free gas. At this stage the well should be evaluated for a stimulation job to restore its FBHP above BPP.
Production data are another source of information for verification or estimation of Pb esp. when no lab measurements are available. For example, on a plot of reservoir pressure against cumulative production (or time), Pb may be estimated as the point where the slope changes. This is due to the fact that below Pb the liberated gas - with its higher compressibility - provides the reservoir with more energy, hence a reduction in pressure decline trend. Another example is a plot of GOR vs. cumulative production (or time): as long as P>Pb, GOR = solution gas oil ratio. It then tends to increase as P falls below Pb. This fact can be used to estimate the time and its corresponding pressure when P=Pb.
Look for the “break” in the material balance Pressure vs. Cum Oil plot. The slope changes as the gas breaks out of solution. Compare that observed break-point with PVT analysis.
When reviewing old field data the bubble point can be determined by observing a flattening in a trend of reservoir pressure versus cumulative production. The pressure drops quickly while the reservoir is above bubble point, then after the reservoir pressure falls below bubble point the pressure will fall more slowly for the same rate of production.