The scaling (solid salt precipitation) potential in the separation plant for a Danish field was evaluated. The analysis covered salt of both high and low solubility. The heavy soluble salts posed no threat as precipitation could be avoided using scale inhibitors. The light soluble salts were also found to not pose any threats as they would go back into solution before the multiphase separator.
A verification study on PVTsim phase equilibrium calculations was carried out to prepare for compositional simulations. Experimental data for verification included water saturation curves for 2 different gas compositions with different water contents and equilibrium phase compositions for various fluids with different contents of MeOH and water.
It was desired to carry out flow assurance simulations for the Reservoir A fluid in a well and pipeline system. Two separator gas samples were taken for a gas condensate from Reservoir A, but no information was available on the liquid produced from that reservoir. Two samples from a nearby Reservoir B were used instead to provide 6 possible fluid descriptions for the Reservoir A fluid with different GORs. Calculations of minimum inhibitor (MEG) amount were also carried out for Reservoir B fluid samples at operating condition. Additionally, OLGA input tables were created for each of the 6 possible fluid descriptions with varying water and inhibitor amounts.
Wax deposition covering a field life period was simulated for a multiphase pipeline. The simulation setup emulated an increase in water cut% and a decrease in flow rate during the 10 years period the simulation was to cover. The simulation results included wax layer thickness, location of wax deposition, volume of deposited wax and pressure, and temperature profiles.
Three different LPG streams were blended at different proportions with condensate into a mixed fluid for transportation in a pipeline. Based on a compositional analysis of each of the streams (both condensate and LPG), it was desired to calculate the amount of wax that may precipitate at pipeline conditions. A characterization was created for a stable condensate analysis, including match of experimental WAT and wax amount. The amount of precipitated wax was then predicted at pipeline pressure as a function of LPG/condensate mixing ratios and temperatures.
An existing EOS model was adjusted to match experimental wax and non-Newtonian viscosity data. The model was used in a wax deposition study of a 30 kilometer multiphase pipeline connecting a new field to an existing platform in the North Sea. 16 production cases were simulated and a detailed analysis was performed of temperature and pressure profiles, thickness, location, and the overall volume of deposited wax.
An EOS model was developed matching the wax appearance temperature and wax amount for a Norwegian reservoir fluid. Manual adjustment of key wax model parameters was required in order to describe the wax amount precipitated as function of temperature. A non-Newtonian viscosity model was developed to match measured fluid viscosities above and below wax appearance temperature.
Based on new data for seven wells the validity was questioned of an existing allocation system applied for multiple fluids produced through the same process plant. A possible inaccuracy could have different reasons. Substantial variations were seen in GOR with time meaning that frequent test separator measurements would be needed to ensure that the feed compositions used in the process plant simulations were representative for the currently produced fluids. It was also investigated whether the simulated oil and gas production would be different if the production from the various wells were mixed before being let to the process plant rather than assuming each feed was processed separately.
The hydrate potential for a pipeline system was evaluated, and the amount of methanol required to inhibit hydrate formation was determined for the system during pre-determined scenarios for normal production, shutdown, and start-up.
Conducted wax deposition study for African oil pipeline. Work included build up at inner side of pipeline and start up analyses.
Multiple fluids from three fields were initially cleaned for OBM contamination. A common EOS model was developed for the fluids while simultaneously regressing to available routine PVT and wax precipitation data. A viscosity model for handling the suspension effects of precipitated wax was developed. While varying key wax precipitation parameters multiple scenarios were simulated to determine the optimum pigging frequency.
A common EOS model was developed for multiple reservoir fluids from five fields while simultaneously regressing to available routine PVT and wax precipitation data. A viscosity model was developed for handling the suspension effects of precipitated wax. While varying key wax precipitation parameters multiple scenarios were simulated to determine how it would influence production if a new field was added to the existing pipeline infrastructure. Shut-in and start-up scenarios were investigated semi-quantitatively and it was found to be unlikely that the oil viscosity during start-up would be high enough to prevent flow from starting.
Project leader for development of model for simulating the effect of commercial wax inhibitors. The model accounts for the sub-cooling of wax solutions due to steric hindrance from wax inhibitor molecules.
Analysis for North Sea oil company of how hydrate risk evaluate with time as gas/oil ratio water cut increased.
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