Asphaltene Precipitation and Deposition is a serious problem which can reduce the oil recovery by reducing reservoir permeability and altering the wettability. It can plug wells and flow lines through deposition and also cause separation difficulties at the separation facilities. Taking preventive measures are always a wise solution rather than attempting to resolve issues when they are occurred. This study proposes a strategy and provides the comprehensive review of the methodology required to predict and prevent Asphaltene Precipitation. Light crude oil samples were taken to be characterized for their thermodynamic properties. The saturation pressure and Asphaltene Onset Point (AOP) were measured at different pressures, temperatures and compositional changes using the Solid Detection System (SDS). Phase diagram and Asphaltene Precipitation Envelopes (APE) were developed. Cubic Plus Association (CPA) equation of state was used to develop the Asphaltene phase envelope using Multiflash (infochem). Titration technique was used to obtain the Asphaltene Floculation point (AFP) using the dead oil and n-Heptane as a precipitant. Effect of different inhibitors was then evaluated using the Solid Detection System (SDS) equipment using the titration technique. Rock-Inhibitor Compatibility was then checked in the reservoir core samples by performing the dynamic core flooding test in the laboratory. Conclusively, this strategy helps to enhance the reservoir performance by minimizing the asphaltene precipitation and will save the cost associated with the consequences of high asphaltene precipitation.

In gas flooding, one of the major problems in implementing foam as a gas mobility control method is the stability of foam. Foam booster when blended with surfactant could improve the foam stability. However, the influence of foam booster on the conventional foam stability and foamability at elevated temperature and presence of inorganic electrolytes is not yet explicit due to limited studies in this area. The objective of the present work was to evaluate the influence of a foam booster on aqueous solution stability, foamability and foam stability when blended with surfactant at different ratios at an elevated temperature in the presence of brine composed of monovalent and divalent ions. Three different surfactants AOS C 14-16 (alpha-olefin sulfonate), SDS (sodium dodecyl sulfate) and a locally manufactured surfactant 'Surf X' were chosen as base surfactants. An amphoteric surfactant lauryl betaine was chosen as a foam booster in this study. The aqueous solution stability was visually evaluated, whereas the bulk foam experiments were conducted in a commercial foam analyzer apparatus. It was found that not all solutions were stable when lauryl betaine was blended. Lauryl betaine did not improve the foam generation time. The foam stability was improved; however, not all solutions were able to generate stable foam. 'Surf X' was able to generate more stable foam as compared to AOS and when blended with lauryl betaine it also required less amount of lauryl betaine to generate stable foam.

Pakistan's production to date is characterized by large oil and gas reservoirs undergoing natural depletion with the help of strong natural aquifer drives. In a few fields, natural aquifer support is supplemented by pattern or peripheral water flood. However, there has been no systematic attempt to define the Enhanced Oil Recovery (EOR) potential within the country. This study is an attempt to extrapolate the potential lies in Pakistani reservoir using Enhanced Oil Recovery methods. This study revisits the screening criteria for the selection of Enhanced Oil Recovery method published by several authors. This study also defines the methodology to screen the Enhanced Oil Recovery method for particular reservoir. Screening criteria is then applied to Pakistani reservoirs. The approach has been integrated into the software in order to make repetitive analysis in an easy way. Finally, after the best selection of Enhanced Oil Recovery Method, the future directions are set and cost analysis is shown in order to proceed the project. The methods considered in this analysis were: water injection, Water alternating Gas injection (miscible and immiscible), polymer, and surfactant – polymer, steam (cyclic and continuous). This study helps to select the optimum Enhanced Oil Recovery method to improve the recovery factor in a quick and efficient way. This is beneficial for the companies that are planning to initiate Enhanced Oil Recovery Project.

Unstable Asphaltene is major concern in oil reservoir under CO2 Water alternating Gas injection due to its unrecoverable damage to reservoir and expensive treatments for production system. Therefore, the effective strategy to control Asphaltene precipitation should be the part of reservoir management. Dealing unstable Asphaltene in Malaysian reservoir was divided into three main parts that were evaluating Asphaltene colloidal stability, Asphaltene Prediction and Asphaltene prevention. Solid Detection System was used to measure the stability and onset pressure of crude oil under reservoir conditions with different amount of gas injections. Various PVT experiments were performed in the laboratory using the PVT cell. PVT data obtained from PVT cell is then fitted with the reliable equation of state (EOS) to generate the Asphaltene phase envelopes. An inhibitor design program was initiated and four inhibitors, Inhibitor A, Inhibitor B, Inhibitor C and Inhibitor D were selected to evaluate their performance in neutral, acidic and basic environment. Titration Test was performed to evaluate the inhibitor efficiency. Inhibitor B in acidic environment was then selected as efficient inhibitor to inject in situ to control Asphaltene precipitation with injection gas. Using this strategy, Asphaltene precipitation is expected to be minimized which will keep the reservoir undamaged and will save large amount of remedial cost.

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