Numerical Simulations of High CO2 Content Flows in Production Wells, Flowlines and Risers

Abstract

There are several challenges associated to the pre-salt development at the Santos basin, such as long distances from the coast, low temperature reservoirs, high pressures, high water depth, among others. Additional aspects contributing to the complex production scenario are related to fluid characteristics and flow assurance. In particular, the high CO 2 content in the dissolved gas is an important characteristic that should be also analyzed, because CO 2 is not only a heavy component, when compared to lighter components present in the gas phase, but has also a high Joule-Thomson coefficient. This affects pressure drop and specially the mixture cooling behavior during decompression. The cooling effect is expected to be strong at high production rates. Thus, the objective of the present work is to evaluate these effects under present and future production scenarios, taking into account increasing CO 2 contents due to re-injection strategies.Two different field configurations were investigated and a variety of operating conditions was used, along with real and model fluids ranging from 5% to 50% CO 2 content (molar basis). PVT data for the model fluids with high CO 2 content were generated by a simulated swelling test with CO 2 of an existing mixture with lower CO 2 content. A parametric study was carried out aiming at investigating primarily the total pressure and temperature drop in the pipeline when the total CO 2 content of the mixture is increased. Furthermore, variation of the fluid properties along the well, flowline and riser was evaluated. Results are also discussed in view of the impact of increasing CO 2 contents and the challenges experienced during simulation of such flows.

Effects of Charged Solute-Solvent Interaction on Reservoir Temperature during Subsurface CO2 Injection

“…The data show an initial, pre-injection reservoir temperature of 58.4 • C and a final post-injection temperature of 58.8 • C at the final 30-day sampling, with a remarkable drop in temperature to 57.6 • C at breakthrough. One may suspect the sharp temperature drop is a result of Joule-Thomson cooling, but the Joule-Thomson coefficient µ JT has been shown to be positive for pure CO 2 at several reservoir representative temperatures across a pressure range of 1 to 500 bar [9],…”

Phase Transitions and Separation Time Scales of CO2–Crude Oil Fluid Systems: Wheel Flow Loop Experiments and Modeling

“…If, during a sweep process, a CO 2 -rich front breaks through and reaches the production well, the CO 2 content in the production stream will increase significantly, indicating the importance of predictability of CO 2 -rich systems. − Nonetheless, the validity of mechanistic models may be questioned if CO 2 -rich dense phases are not treated appropriately . Furthermore, CO 2 -rich hydrocarbon mixtures raise pipeline integrity and flow assurance concerns due to potential asphaltene precipitation, , corrosion challenges, swelling of the polymeric liners, and calcium carbonate scaling .…”

Multiphase mixture model to predict temperature drop in highly choked conditions in CO2 enhanced oil recovery

“…Due to the strong Joule-Thomson cooling (JTC) effect of CO 2 , the high CO 2 content in associated gas is an important characteristic that should be analyzed [4]. When the fluid with high CO 2 content flows through a choke valve, the rapid cooling can cause the temperature downstream of the valve to drop below the freezing point.…”