In the last few years, large efforts have been made to develop advanced and smart technologies that can predict and prevent asphaltene precipitation. In the history of asphaltene deposition science, two schools of thought have emerged to predict the phase behavior of asphaltene. One school uses colloidal science techniques, believing that asphaltene exists in oil at a colloidal state. The other school adopts thermodynamic methods, believing that the asphaltene occurs in oil in a true liquid state. The main drawdowns of asphaltene deposition in some reservoirs that are prone to asphaltene precipitation are the alteration of reservoir rock's wettability, and the plugging of the formation, flowlines and separation facilities. Different production strategies have been developed to eliminate or reduce the asphaltene precipitation. As asphaltene properties are dependent on its composition, as well as the reservoir temperature and pressure, thermodynamic and kinetic control strategies are utilized to control the pressure and temperature of the system or the conditions of solid formation. Common intervention techniques include stimulating the well periodically using a mixture of acid, xylene, and mutual solvent. Advancement in the asphaltene flocculation-inhibitor treatments allows it to be used in treating the asphaltene in the reservoir without damaging the formation. There are some limitations and environmental restrictions on the current conventional intervention techniques associated with using low flash-point chemicals. These limitations can be resolved by using environmentally friendly techniques, such as laser energy to disturb asphaltene particles. This paper will discuss the asphaltene precipitation and deposition phenomena, preventive and detection techniques, and intervention methods and their limitations, providing a comprehensive overview on the current practice in asphaltene remediation and prevention.

Alcohol ethoxylate-based nanosurfactant was experimentally assessed to be used in HCl acid-based stimulation recipes. The surface tension of the surfactant with different stimulation additives was compared with commonly-used linear and branched alcohol ethoxylate-based surfactants. Nanosurfactant showed the lowest CMC of 2 gpt compared to 3 and 5 gpt for branched and linear alcohol ethoxylate-based surfactants, respectively at 77°F. The Nanosurfactant illustrated the highest performance in lowering the surface tension of water to 17 dynes/cm at 280°F. Spent 20 wt% HCl acid and mutual solvent affected the performance of nanosurfactant by increasing the surface tension at temperatures up to 300°F. Live 20 wt% HCl acid showed insignificant effect on the performance of nanosurfactant. Despite the negative interactions with number of stimulation additives, nanosurfactant showed superior surface tension lowering abilities compared to linear and branched alcohol ethoxylate-based surfactants.

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This paper represents a study of the application of nano-surfactant in the acid stimulation and EOR operations. The performance of the novel surfactant was compared with commercial alcohol ethoxylate surfactants. Different acidizing additives were added to the surfactants under study to evaluate their behavior using surface tension measurements. A negative behavior of the nano-surfactant with corrosion inhibitor, H2S scavenger, and iron control and reducing agents were observed. Regardless of the effect of these additives on the surfactant performance, the nano-surfactant still provides a better performance overall compared to commercial alcohol ethoxylate surfactants. Interfacial tension experiment of the nano-surfactant with condensate samples was performed giving an average IFT of 8 dynes/cm at 160 °F.

This paper discusses a method for optimizing production facilities design for onshore/offshore wells during new field development. Optimizing the development of new oil and gas fields necessitates the use of accurate predication techniques to minimize uncertainties associated with day-to-day operational challenges related to wells, pipelines and surface facilities. It involves the use of a transient multiphase flow simulator (TMFS) for designing new oil and gas production systems to determine the feasibility of its economic development. A synthetic offshore oil field that covers a wide range of subsurface and surface facility data is considered in this paper. 32 wells and two reservoirs are considered to evaluate the effect of varying sizes of tubing, wellhead choke, flowline, riser, and transport line. A detailed investigation of the scenario of emergency shutdowns to study its effect on the system is performed using TMFS. Other scenarios are also evaluated such as startup, depressurization, pigging, wax deposition, and hydrate formation. This paper provides a method to minimize the cost by selecting the optimum pipelines sizes and diameters, and investigating the requirements of insulation, risk of pipeline corrosions and other related flow assurance parameters. Different facility design scenarios are considered using TMFS tool to achieve operational flexibility and eliminate associated risks. Pressure and temperature conditions are evaluated under several parametric scenarios to determine the best dimensions of the production system. This paper will also provide insight into factors affecting the flow assurance of oil and gas reservoirs.