Fluid Flow And Heat Transfer In Wellbores Pdf Download

ADVANCED SIMULATION OF TRANSIENT MULTIPHASE FLOW &FLOW ASSURANCE IN THE OIL &GAS INDUSTRY Djamel Lakehal1,2* 1. ASCOMP GmbH Zurich, Zurich, Switzerland 2. Mar 23, 2015. Full-Text Paper (PDF) Heat transfer issues in offshore wells have become more relevant in recent years with the exploration of high-pressure, high-temperature reservoirs. Pixelview Playtv Mpeg 8000gt Driver Windows 7 Download. New production scenarios often present challenges related to flow assurance, well drilling, completion and workover.

• 1.2k Downloads Abstract The interpretation of Distributed Temperature Sensing (DTS) real-time temperature data from downhole is essential to understand wellbore production and production operations management. This paper presents a multi-phase wellbore thermal behavior prediction model for the interpretation of wellbore fluid thermal responses. Based on our previous simulation results on single-phase flow in horizontal wellbores, a two-phase flow model ( η s-driven model) is developed for steady-state conditions in the form of homogeneous and drift-flux models applied to both openhole and perforated completion types. Case studies include the examination of water entry thermal effect and gas mixing thermal effect comparing between the two modeling approaches. Results show that the phenomena of water breakthrough and gas blended in oil can be detected from fluids temperature profiles.

For two-phase flow, the homogeneous model can be used if the no-slip between phases assumption is valid. Because of the no-slip assumption of the homogeneous model, the volume fraction of each phase can be directly evaluated by the ratio of the flowrate of one phase to the total volumetric flowrate. For such two-phase homogeneous conditions, Eq. ( ) would still apply by treating the two phases as a pseudo-single phase with average properties.

Appendix provides the definition of applicable two-phase variables. In homogeneous oil–gas flow, the liquid holdup is estimated as.

(11) Two-phase model: drift-flux model In a drift-flux model, slip between phases is considered. Because of the non-uniform velocity profiles, one phase of two-phase flow is transported at a higher velocity than the other phase. For oil–gas two-phase flow, gas tends to have a higher velocity than oil; while for the water–oil flow, it depends on whether the flow pattern is O/W (oil phase dispersed in water phase) or W/O (water phase dispersed in oil phase). A dispersed phase has a higher velocity than the continuous phase. Compared to the homogeneous model, the evaluation of holdup (in situ volume fraction) of each phase in drift-flux model comes from an empirical correlation based on experiments. Two mechanisms are considered in the oil–gas two-phase flow drift-flux model. First, there are non-uniform velocity and phase distribution profiles over the cross section of the wellbore.

In the center of a wellbore, gas tends to have the highest concentration, with the highest local mixture velocity, so the average gas velocity is higher than that of oil. Second, due to a buoyancy effect in vertical wells, gas has the tendency to rise vertically through oil (Shi et al.

The drift-flux model for the oil–gas phase can be expressed as. A sensitivity study of the proposed two-phase flow model in several scenarios is conducted. Both homogeneous and drift-flux models have been applied in both oil–water and oil–gas flows. In the oil–water flow cases, a thermal effect of water entry on wellbore is discussed; while in the oil–gas flow cases, another thermal effect of an oil–gas mixture production at different gas flow rates is analyzed. An openhole wellbore condition is initially applied in the case study.

A perforated wellbore type is also applied in oil–gas flow case to compare the sensitivity of thermal response between two wellbore types. Tables, give the openhole wellbore description and fluids compositions. For consistency purposes, reservoir pressure and temperature for all the cases were taken with the values of 3900 psia and 190 °F, respectively.

The homogeneous oil–water flow model is initially applied in the openhole wellbore condition. Figure gives water holdup profiles in three cases.

When water enters at the toe of the wellbore, its holdup is first maintained at 1 because there is no oil production during that time. As oil production begins, water’s cumulative production does not change and its holdup begins to decrease. When water enters wellbore at the middle and heel of wellbore, its holdup is zero until it begins to produce. When fluid reaches the heel of the wellbore, the water holdup is the same in all three cases, i.e., about 0.24. Figure shows pressure responses in all three cases with comparison of a single-phase oil case.

Compared to single-phase oil flow pressure response, the pressure profiles of two-phase cases are continuous and have no obvious differences. Therefore, one could not recognize the entry of water using pressure response profiles alone. Figures,, present temperature responses in all three cases with comparisons of the single-phase cases. When water enters the wellbore at different locations, different temperature responses are observed from Figs.,,. The temperature profile begins to deviate from the single-phase fluid case at the location where water enters the wellbore. In order to show the detailed thermal behavior of single-phase oil and oil–water case, Fig. Is plotted to give the overall temperature contribution of the two cases (single-phase oil and oil–water flow with water enters at toe).

Compared to single-phase oil case, oil–water flow is less heated by the friction effect and less cooled by the isentropic coefficient. The combination of three factors result in a smaller temperature increment compared to single-phase oil case, in which the water entry could be detected. Therefore, temperature response profiles in wellbore flow may be utilized to interpret the water entry phenomenon during production.

The main difference between the drift-flux model and the homogeneous model is that the drift-flux model considers slip in evaluating phase holdup and velocity. In oil–water flow, to make each thermal profile in continuous format, we assume that the flow pattern in the flow system is W/O, which means that the water phase is dispersed in the continuous oil phase. Water holdup profiles are given in Fig.. Compared to the water holdup calculated by the homogeneous model in Figs., has a similar trend of water holdup.

Figure is generated to show the difference between these two results. Let us consider the entry of water at the mid-section depicted in Fig..

It is shown that the homogeneous model over-predicts the water holdup along the wellbore, compared to the drift-flux model. That is because the two models utilize different algorithms in calculating the phase holdup. In the homogeneous model, the phase holdup is calculated directly by the cumulative production of each phase, whereas in the drift-flux model, the phase holdup is calculated by drift-flux correlations. The result of the velocity profile for the middle location case is in Fig.. V o and V w in the figure give the velocity profiles of oil and water phase, respectively. V m is the mixture velocity of the two-phase flow calculated in the homogeneous model.

Figure shows that the dispersed water phase travels at a higher velocity than the oil phase along the wellbore, while the mixture velocity has a value between the oil and water velocities. The velocity profiles obey one basic assumption of drift-flux model—one phase is transported at a higher speed than another phase.

Pressure profiles in each case are generated by the drift-flux model as shown in Fig.. Similar to the pressure profiles in the homogeneous model, pressure profiles are almost overlapped with each other. So, one could not detect the water entry effect and water location from pressure profiles. Figures,, give the temperature profiles of each case relative to the single-phase oil case. There are similar phenomena in temperature profiles generated by the drift-flux model compared to the homogeneous model. Temperature of two-phase flow deviates from that of single-phase flow predictions at the location where water begins to enter. Similarly, we first show the result of the homogeneous model in the openhole wellbore type.

Gas holdup is given in Fig.. Since gas enters the wellbore simultaneously at each segment, the cumulative production of gas makes its holdup increase from toe to heel. The larger the gas flowrate, the higher the holdup gas phase will be. Figure shows pressure profiles in three cases. With the same oil flowrate, the largest gas flowrate case results in the largest pressure drop, then the medium and low gas flowrates. Figure shows the temperature profiles in three cases.

It is interesting to find that in three cases, from toe to heel, temperature first increases then decreases due to the effect of gas entry. As demonstrated in the single-phase case study, oil is heated while gas is cooled along the wellbore. When the two-phase flows come together, the fluid mixture at the first half of the wellbore experiences heating like the oil phase; then it is cooled like the gas phase. Since a higher gas flowrate leads to a larger pressure drop, the oil–gas mixture in the largest gas production has the largest range of temperature changes. Due to the cooling effect in the gas phase, it is easy to diagnose entry of the gas during oil production from its temperature profile. Figure shows the comparison of overall temperature contributions between two cases (single-phase oil and oil–gas flow with highest gas rate).

It is observed that compared to single-phase case, oil–gas flow experiences more frictional heating and isentropic cooling. The energy exchange cools the flow at the same time. The combination of three factors gives a different thermal behavior of oil–gas flow compared to single-phase oil flow. Figure is given to compare the difference between holdup results in the two models. As illustrated, when slip is considered in the drift-flux model, the gas holdup becomes smaller compared with the homogeneous case. Again, this is caused by different algorithms in evaluating phase holdup, and the homogeneous model tends to over-predict the gas holdup. The velocity profile in the high gas flowrate case is given in Fig..

As expected, due to the slip between the two phases, the gas phase has a higher velocity than that of the oil phase, and the mixture velocity in homogeneous model is also between two velocity profiles. Figures, present pressure and temperature profiles in the drift-flux model.

The pressure and temperature profiles have similar trends compared to those in the homogeneous model shown in Figs.,. The results discussed so far for the two-phase flow are in openhole wellbore type. For thermal model in an openhole wellbore, the pipe’s open ratio ( gamma ) is 1, so that energy exchange only appears in the mass exchange part. In this case, we introduce heat conduction into our model for a perforated wellbore type and compare the result with the openhole wellbores. Spartan Trailer Serial Numbers here.

Appendix shows the development of overall heat transfer coefficient calculations. Fluid and perforated wellbore properties are given in Table (Yoshioka et al. A perforated wellbore type has been applied in the same oil–gas flow case. Pressure and temperature results are generated by the drift-flux model. Figure shows pressure profiles in three oil–gas cases.

Similar profiles can be found compared to the openhole case in Fig.. However, due to smaller roughness of the wellbore, the pressure drop of perforated wellbore fluid in the figure is relatively smaller than that of the openhole wellbore fluid. Figure gives temperature profiles in this case. Temperature change in a perforated wellbore is not as significant as that in an openhole wellbore. Two reasons can be considered for this fact. First, the smaller pressure drop weakens the effect of the isentropic thermal coefficient, leading to the wellbore fluid being less cooled. Second, the heat conduction from reservoir to wellbore always has an opposite effect in determining the overall trend of temperature change.

For example, in this case, the first half of the wellbore from toe to the middle is being heated, while the heat conduction cools the wellbore fluid because the reservoir temperature is lower; the remaining half of the wellbore from middle to heel is being cooled while heat conduction heats the wellbore because the reservoir temperature is higher. Combination of these two factors results in a non-sensitive thermal response of a perforated wellbore fluid. Based on our studies on two-phase flow wellbore fluids systems, it is shown that the η s-driven model can be implemented to analyze two-phase wellbore flow thermal behaviors during the production of oil, gas and water. The Entry of the undesired phases including water and gas can be detected via the temperature profiles. For perforated wellbores, the thermal response is not as sensitive as in the openhole case. Results show that our models (homogeneous and drift-flux) can be applied to effectively predict and interpret wellbore fluid thermal behaviors at steady state.

Further experiments are needed to test the performance of the two types of models. The proposed models can be further developed for transient flow conditions to analyze the early time regime. In addition, to match field data, the reservoir model is necessary to be coupled with the wellbore model to generate more realistic flowrate, reservoir pressure and temperature as inputs before calculating the wellbore temperature profile. Also, flash calculation can be applied in every block of the wellbore in an oil–gas two-phase flow system to have a more accurate evaluation of gas entry effect and a better estimation of oil and gas production on the surface. Appendix A: two-phase flow variables.

As a new improved oil-recovery technique, multi-thermal fluid injection technology through a horizontal well has been widely used in the development process of heavy oil reservoirs. The flow and heat transfer characteristic of multi-thermal fluid in horizontal wellbore is significantly important for the productivity evaluation and parameters design of the horizontal well. Considering the specific physical properties of multi-thermal fluid, fluid absorption in perforation holes and pressure drop characteristics along the horizontal wellbore, this paper developed the flow and heat transfer model of multi-thermal fluid in perforated horizontal wellbore.

In order to evaluate the heating effect of the multi-thermal fluid, a concept of effective heating length of a horizontal well is proposed. Then, a sensitivity analysis process is performed to study the influence of reservoir/fluid parameters and operating parameters on the flowing process of multi-thermal fluid in horizontal wellbore. Simultaneously, using the method of orthogonal numerical test, differential analysis and variance analysis are also conducted. Results show that the flowing process of multi-thermal fluid in horizontal wellbore includes a single-phase flowing process and a gas–liquid two-phase flowing process. The influence of oil viscosity on the flow and heat transfer characteristics of multi-thermal fluid in horizontal wellbore is most significant. Thereafter, the solution of our semi-analytical model is compared against the test results of an actual horizontal well from an oilfield in China.

It is shown that the model results are in good agreement with the real test results. This model could be used to calculate and predict the flow and heat transfer characteristics of multi-thermal fluid (or saturated steam) in a perforated horizontal wellbore.

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