Cellulose –Earth’s most abundant biopolymer–represent an enormous carbon-neutral renewable resource of biomaterials and bioenergy. The dissolution of cellulose with environmentally friendly and efficient solvents/methods is an important and challenging for further chemical processing. In recent years, room temperature ionic liquids (ILs)- a attractive “green” and “designer” solvent-have emerged as a potentially attractive “green” solvent for dissolution of cellulose for further processing. In general, dissolution of cellulose in ILs via conventional heating system requires high temperature and long pretreatment time. This study reports the effect of pressure on the dissolution of cellulose in IL [C2mim][OAc] (1-ethyl-3-methylimidazolium acetate). The effects of temperature and pressure on cellulose dissolution time were investigated using high Pressure Solubility Measurement System (HPSMS). It was found that as the pressure and temperature increased, the dissolution time decreased significantly. For comparison, the original microcrystalline cellulose (MCC) and regenerated cellulose from ILs after dissolution were characterized using scanning electron microscopy (SEM) and thermogravimetric analysis (TGA). The results clearly revealed that the thermal stability of regenerated cellulose were reduced.

Process upsets in high oil production facilities can hinder optimal plant performance and result in system shut-ins. Based on several successful demulsifier chemical trials, scientists and engineers have developed a guideline on how to optimize production throughout the chemical trial period. Factors such as chemical injection rate, export crude oil monitoring (basic sediment and water (BS&W) and salt), discharge water quality(from the water-oil separator (WOSEP)), and transformer voltage fluctuation (dehydrator and desalter) plays an important role in minimizing the system upset. Prior to chemical trial, scientists and engineers analyze the process system to understand individual vessel functions and limitations. Incumbent chemical program provides baselines and key performance indicators (KPIs) set minimum oil specifications before exporting oil to refineries. Demulsifier injection rates are reduced based on the chemical program optimization proposal until it reaches the dosage limit while maintaining stable process throughout the trial. Therefore, scientists and engineers may evaluate the demulsifier’s performance based on the KPIs set with no system upset. Fast fluid separation in the High Pressure Production Traps (HPPTs) is an important strategy in order to improve process system’s performance. High volume oil production systems typically have two HPPTs in parallel for initial water separation. Downstream of the HPPTs is the Low Pressure Production Trap (LPPT), which is mainly used for gas separation. Oil continues to the dehydrator to finish the dehydration to meet the pipeline BS&W requirement. The dehydrator is where the transformer is located for the electrostatic grid and high amounts of water separation can cause fluid levels to fluctuate and trip the transformers. Throughout several field trial experiences, demulsifier rates can be optimized (reduced) further when it shows increased water separation at HPPT vessels. Clear water from HPPTs discharge, valves in water leg HPPTs open more (%), stable voltage grid (dehydrator/desalter), and less than 0.2% BS&W with less than 10ptb salt recorded at the export oil gives a good indication that the process is stable. Thus reduced the risk for system upset. This paper summaries the best approach to optimize chemical rates in high volume oil production systems, analyzes qualitative and quantitative system checks to verify stable operations, and discusses potential risks involved when reaching lower limits of effective chemical rates.

This paper describes field experience of designing a successful scale squeeze program for an oil well. This was done utilizing an adsorption isotherm derived from a core flood data from other reservoir. Correlation and reliability of the adsorption isotherm with actual field flow back data after squeeze treatment for a period of 18-month are given. Moreover, utilizing the knowledge generated, a bespoke multilayer adsorption isotherm was optimized for a treated well for more efficient squeeze design for next treatment. In order to achieve our objective, an adsorption isotherm from other reservoir core flood was first generated. With the knowledge not limited to current candidate well production rates, well properties, perforation height, number of zones and other essential parameters, a 18-month squeeze treatment program was designed. Water chemistry 18-month data was utilized to validate the scale squeeze design. An improved multilayer adsorption isotherm bespoke for this well was generated. In conjunction with flow-back production data, a scheduled sampling program and water analysis utilizing Inductively Coupled Plasma (ICP) for post treatment Scale Inhibitor (SI) residuals data was collected to validate the adsorption isotherm derived from other reservoir. As predicted by the model for post treatment monitoring, the SI residual concentration; back calculated from SI chemistry utilized for the treatment are found to have an excellent correlation with the adsorption isotherm derived from a different reservoir. Hence, the 18-month squeeze design derived from a different reservoir was a great success. The slight difference between real flow back data and the adsorption isotherm generated from other reservoir become a benchmark to derive an improved adsorption isotherm to optimize the scale inhibition protection than the current treatment. In summary, parameters such as mineralogy study, porosity, permeability, crude properties and dynamic scale loop (DSL) study are the utmost important information to be analyzed prior using other reservoir core flood data as reference. As results shown, these are the best way to generate squeeze design with limited information had in hand.