Shawn David Taylor

Asphaltene Deposition Measurement and Modeling for Flow Assurance of Subsea Tubings and Pipelines

High-pressure deposition cell is used to measure asphaltene deposition from asphaltenic crudes under realistic field conditions of pressure, temperature, composition, and shear. The laboratory-scale data is then used to fine-tune and validate a recently developed asphaltene deposition model for the high-pressure deposition cell. Sensitivity analyses are performed to indicate the impacts of changes in model parameters on the deposit predictions. Through this exercise, the number of model parameters is reduced from six to two. The model predictions are verified with the deposition experimental data that were not used for tuning. The identified parameters then become inputs to the asphaltene pipe deposition model for predictions of deposit thickness along the tubings and pipelines in the field. Introduction Deposition of asphaltenes in well bores and transportation pipelines as a result of reduction in pressure or change in composition of the reservoir fluid has been a flow assurance concern for the oil and gas industry. The large capital and operating costs associated with prevention and remediation of deposits have created the need for improved methods to measure and model for optimization of system design and operations while minimizing risk of deposition. A key to development of strategies for its prevention and mitigation is the proper measurement and modeling of the asphaltene deposition. Asphaltenes in crude oils that exhibit asphaltene precipitation and deposition behavior during primary depletion are typically undersaturated. During reservoir production at a constant temperature, once pressure decreases to the asphaltene precipitation onset pressure, asphaltenes start to precipitate and potentially deposit in the wellbore region and flow lines. Typically, the amount of precipitated asphaltenes increases as the pressure decreases, and reaches a maximum at the bubblepoint pressure. Asphaltene precipitation is a thermodynamic process which is mainly a function of pressure, temperature, and fluid composition. Asphaltene deposition, on the other hand, is a much more complex process and also depends on flow shear rate, surface type and characteristics, particle size and particle-surface interactions. Asphaltene precipitation is a necessary condition for the formation of obstructions but it is not a sufficient condition for deposition. After precipitation, asphaltene particles must deposit and stick to a surface before they can become a flow assurance problem in straight flow lines. RealView, a high-pressure deposition cell based on the Taylor-Couette flow principles, is a laboratory tool for generating organic solids deposits under a wide variety of operating conditions. This equipment has been used to measure the deposition rate of waxes and asphaltenes from live fluids under laminar and turbulent flow conditions. Although the high-pressure deposition cell is a capable tool in generating asphaltene deposits under a wide variety of operating conditions, the deposition rates obtained by this laboratory-scale equipment cannot be directly applied to the field. A deposition model can, however, fill this gap and link the laboratory data to the field environment. Typically, the data are used to fine-tune and validate deposition models and thereby identify their parameters. The refined models are then used to predict deposition in the field. Recently an asphaltene deposition model was developed by Eskin et al.. The developed model has six parameters that need to be determined using experimental data. In this paper, some of the experimental data obtained by RealView are used to tune the asphaltene deposition model. The number of model parameters is then reduced through sensitivity analysis. Next, the tuned model is validated using

A Systematic Workflow Process for Heavy Oil Characterization: Experimental Techniques and Challenges

Heavy crude oil reserves are steadily gaining attention as the worlds energy demand increases. The fluid characterization of heavy oil and bitumen is critical in deciding best extraction, production, and processing methods of a heavy oil asset. High viscosity, low API, low saturation pressure, and low GOR impose challenges in measuring fluid properties of heavy oil. Such challenges include fluid sampling, sample handling, cleaning and de-emulsification of heavy samples and slow evolution of gas from oil phase during pressure-volume-temperature (PVT) testing— e.g., constant composition expansion (CCE) experiment. Due to these challenges, the accurate and reliable fluid characterization of heavy oil becomes more difficult. Currently, no industry standards exist for heavy oil property measurements. More often, heavy oil property measurements are performed in the same way as black oil fluid property measurements. This poses a big risk in obtaining erroneous fluid properties measurement for heavy oils. This paper summarizes the heavy oil fluid characterization technique that includes fluid sample handling, PVT analysis, fluid viscosity, emulsion and rheology, slow kinetics of gas evolution during CCE experiment, solvent solubility study, steam stripping study, and high temperature vapor-liquid equilibrium of oil-solvent-steam systems. The experimental methodologies, including the merits and experimental limitations for these measurements are discussed in detail. Example results of heavy oil property measurements for each technique are presented. Finally, a systematic heavy oil characterization workflow is proposed for various types of production processes such as cold depletion, steam flood and heavy oil flow assurance characterization. Introduction Ever increasing energy demand has inflated the production interest in heavy oil and bitumen around the world. One of the keys to meeting this increasing demand for heavy oil is a thorough characterization of the reservoir fluids and the potential variability in fluid characteristics across a heavy oil field. ‘Heavy’ or ‘viscous’ oils are typically defined (based on UNITAR guidelines) as either heavy oil or bitumen. Heavy oils have a API gravity between 22.3 and 10 API and a viscosity between 100 – 100,000 mPa.s. Bitumens are oils where the API gravity is less than 10 and viscosity exceeds 100,000. Oils with less than 10 API gravity may be referred to as extra-heavy or ultra-heavy oil due to its density being lower than water (Martinez et al, 1987). Fluid characterization of heavy oils and bitumen is required for several purposes, including oil quality evaluation, selection and optimization of production process, facilities planning, transport planning, and process monitoring. In the case of selecting and optimizing processes to extract heavy oil from a reservoir, fluid characterization efforts are normally focused on understanding the mobility and changes to the mobility under different production conditions. Such understanding and ability to manipulate mobility depends on of the knowledge of petroleum fluid thermodynamics, chemistry and transport phenomena.