Volume pressure and temperature relationship in oil

Chapter 2 Pressure-Volume-Temperature for Oil - ppt download

volume pressure and temperature relationship in oil

Pressure-Volume-Temperature for Oil. PVT analysis – PVT relationship. 1 int). ( po bubble of because complex simple condition d undergroun. Oil condition scf. Empirical equations for estimating saturation pressure, oil formation volume factor Therefore, several empirical correlations such as the equation of states. This required a knowledge of the gas solubility-bubble-point-pressure relationship of the oil and gases associated in the reservoir. In considering the manner in.

  • Chapter 2 Pressure-Volume-Temperature for Oil
  • Phase diagrams for reservoir fluid systems
  • Log in to your subscription

Because the saturation of liquid is low, only the vapor phase flows to producing wells. Thus, the overall composition of the fluid remaining in the reservoir changes continuously. The phase diagram shown in Fig.

The preferential removal of light hydrocarbon components in the vapor phase generates new hydrocarbon mixtures, which have a greater fraction of the heavier hydrocarbons. Differential liberation experiments, in which a sample of the reservoir fluid initially at high pressure is expanded through a sequence of pressures, can be used to investigate the magnitude of the effect of pressure reduction on the vapor composition.

At each pressure, a portion of the vapor is removed and analyzed.

Phase diagrams for reservoir fluid systems -

These experiments simulate what happens when condensate is left behind in the reservoir as the pressure declines. As the reservoir fluid becomes heavier, the boundary of the two-phase region in a diagram like Fig. Thus, the composition change also acts to drive the system toward higher liquid condensation.

Such reservoirs are candidates for pressure maintenance by lean gas injection to limit the retrograde loss of condensate or for gas cycling to vaporize and recover some of the liquid hydrocarbons. Bubblepoint reservoirs Bubblepoint reservoirs are those in which the temperature is less than the critical temperature of the reservoir fluid point D in Fig. These reservoirs are sometimes called undersaturated because the fraction of light components present in the oil is too low for a gas phase to form at that temperature and pressure.

Isothermal pressure reduction causes the appearance of a vapor phase at the bubblepoint pressure.

volume pressure and temperature relationship in oil

Because the compressibility of the liquid phase is much lower than that of a vapor, the pressure in the reservoir declines rapidly during production in the single-phase region. The appearance of the much more compressible vapor phase reduces the rate of pressure decline. This technique is especially applicable to regions with high geothermal gradients, where the temperatures recorded at the time of logging runs can be significantly lower than the static temperature.

Measurement of reservoir pressure and temperature Many techniques exist for obtaining bottomhole reservoir pressure and temperature. A variety of logging techniques may be used. See Acquiring bottomhole pressure and temperature data for more information. The techniques described below are emerging techniques or special considerations. Optical fiber measurement of pressure and temperature Several systems are being developed to provide pressure and temperature measurements distributed over the length of an optical fiber that is permanently deployed in the completion.

An advantage of fiber optic technology is that the sensors have no electronic components at depth, so they tend to be more reliable. Furthermore, optical sensors are: Immune to shock Not prone to electromagnetic interference Operable at high temperatures Fiber optic technology is based on exposing the fiber to periodic ultraviolet UV light patterns that induce a "grating" on it.

Pressure and temperature variations change the reflection wavelength of the gratings and can be decoded with respect to the fixed, incipient operating wavelength. The system is self-referencing. Every point distributed along the length of the fiber has the potential to generate a different temperature measurement. The advantages are measurement of a permanent temperature gradient over the length of the fiber and the ability to select specific measurement points.

Reservoir pressure and temperature

In one reported case, temperature measurements taken along a horizontal wellbore at different times showed steamchests, water breakthrough, crossflow, and flow behind pipe. Pressure is measured by sensors located at discrete, fixed points along the fiber.

volume pressure and temperature relationship in oil

At the sensors, the fiber is cut, and its ends are placed face-to-face in a proximal arrangement. The face-to-face spacing is measured by successive reflections of the light wave.

Changes in the value of the spacing reflect the environmental pressure around the fiber at that point. The self-referencing technique uses the distributed temperature measurement for suitable corrections.

For GOR greater than these values, the oil becomes saturated with gas and gas breaks out. The system becomes two phase gas and liquid flow. Figure 4 presents the line pressure drop per unit length as a function of oil stock tank volume rate, GOR, and feed temperature. In this figure and subsequent figures, the solid lines are for the feed temperature of Figure 4 indicates that as the GOR increases from 0 to The dividing point is at a saturation solution gas of At higher temperature the increase of GOR reduces the pressure drop when solution gas is under saturated but increases the pressure drop for GOR greater than the saturated solution gas.

Bubble point pressure of the feed to the gathering line as a function of solution gas at nominal line temperature of Variation of pressure drop per unit length with oil stock tank volume rate, GOR, and temperature — Solid curves for This figure indicates that as the RS increases, the oil relative density decreases. Note as the temperature increases the solution gas RS decreases.

Variation of oil relative density with solution gas and temperature along the gathering line at kPag for Lines are for feed temperatures of The reduction of viscosity causes pressure drop to decrease. The simulation results Figure 3 indicated that for GOR less than The increase in pressure drop due to higher GOR and higher total flow rate is more than the decrease in pressure drop due to reduction of oil viscosity as a result of solution gas. This figure also indicates that at zero and low GOR, in which the system is single liquid phase, the temperature has a larger impact on the crude oil viscosity.

Variation of oil viscosity with solution gas, along the gathering line at kPag for The lines are for temperature of Figure 7 indicates that the oil velocity remains constant along the line but the gas velocity increases due to pressure drop in the line and more gas coming out of the solution.