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Title: Topside facilities’ ability to handle a new blend of crude oil
Authors: César, Sandro Duarte 
Keywords: Petroleum -- Refining -- Angola;Petroleum industry and trade -- Angola
Issue Date: 2022
Publisher: Cape Peninsula University of Technology
Abstract: Angola is the second largest oil producing country in sub-Saharan Africa, producing around 1.4 million barrels of oil and 17.9 billion cubic feet of gas per day of production. The recovery of crude oil and natural gas from underground sources requires separation and stabilisation treatment of all the individual phases since both exist as a hydrocarbon-water mixture in the rock formation. This study introduces an approach to the factorial design of an offshore topside process facility, considering the effect of an oil field fluids’ composition and arrival temperature on the production facility’s behaviour, which was not considered during the facility’s original design phase. The objectives of this study were to: 1.) evaluate and perform verifications to confirm the suitability of the existing facility to meet the desired outlet conditions by processing fluid from the new Múcua field which has an arrival temperature of -7ºC at the top of production riser-c (PR-c); 2.) evaluate the equipment handling capability past the total liquids design capacity by means of a detailed process train evaluation of each topside system with a clear identification of potential bottlenecks and its optimisation for debottlenecking; 3.) develop blowdown system verifications considering the recommended updated design cases and operating conditions. A new fluid blend including fluid from the Múcua field through PR-c was used for the simulations of case studies A to F using Aspen Tech HYSYS, based on the PR-c alignment either to the high pressure (HP) separator (with gas lift) or to the Test separator (without gas lift), for the six operational scenarios with operating temperatures, -7, 5, 36 and 50°C, and operating pressures of 7 and 19 barg. Herein the relationship between these variables was investigated and the results compared with the original design specifications of the equipment for possible bottlenecks, which provided data for a governing case selection. An estimation of the safe production outcomes with the new fluids addition as a function of the pressure and temperature was therefore obtained. From the simulations and MySEP evaluations, the gas flow rate at the intermediate pressure (IP) and low pressure (LP) separator was found to be greater than the original design for cases A, B, D and E, with a high liquid carryover in the gas stream and verifications on the separators’ gas outlet pressure control valves (PCVs) providing evidence of their lack of adequacy for the full gas flow rate as per the original design. The main injection gas compressing system showed no major concerns to accommodate all six case studies, despite the slightly higher condensate flow rate for cases A, B and C at the 2nd stage scrubber than the design flow rate specification. The actual volumetric flow rate passing through the 1st stage flash gas compressor suction cooler for cases A, B, D and E was greater than the original design value, therefore the flash gas compressor system was found unlikely to handle all the gas from cases A, B, D and E due to a relatively high pressure drop across the coolers. This led to a portion of the process gas being flared from the LP/IP separator, which is undesired as it poses environmental constraints and as such was found to be the major bottleneck. While there were no concerns found for the blowdown scenario and flare system, the gas dehydration and fuel gas, the produced water system and cooling medium system, the overall heating medium duty requirement was exceeded for cases D and E, therefore requiring a greater heating load for the crude oil heater to heat the incoming fluids to the operational temperature of 90°C needed to meet the product’s true vapour pressure (TVP) specifications. Case F was selected as the governing case based on the operating parameters and production figures prior to the introduction of the new field fluids into the system. From the outcomes of the simulation and evaluations with the Múcua fluid tie-in under Case F’s configuration, it was found out that the water flow rate at the LP separator was greater than the original design and the existing line size was validated to be able to handle the increased flow rate. However, the pressure drop could be a problem since the water flow rate for the 2nd stage flash gas compression scrubber was found to be above the design case as well, the production flow rates would therefore need to be increased gradually and closely monitored to address this bottleneck. From this study, it was concluded that in order to start-up the facility with the Múcua field fluid tied-in without major bottlenecks under case F configuration with a production expectancy of 81170 barrels of oil per day, 73.06 million standard cubic feet per day across the HP separator and a cargo of TVP ≤ 14.7 psia at storage conditions: 1.) the crude oil heaters should be upgraded from 100 to 128 plates to have increased flexibility and less gases flashing in the cargo tanks; 2.) the heating medium temperature should be increased to the maximum capacity sustained by the exchangers Hydrogenated Nitrile Rubber (HNBR) gaskets; 3.) the crude oil coolers should be bypassed as the crude/crude exchangers are expected to cool the dead oil to ≤ 50°C; 4.) the subsea chemical injection requirements should be revised to improve separation; 5.) monitor the Múcua fluids water cut and arrival temperatures; as well as 6.) monitor the flash gas compressor systems performance.
Description: Thesis (MEng (Chemical Engineering))--Cape Peninsula University of Technology, 2022
Appears in Collections:Chemical Engineering - Masters Degrees

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