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Akbarzadeh, Kamran (Schlumberger) | Ratulowski, John (Schlumberger) | Lindvig, Thomas (Schlumberger) | Davies, Tara Lynn (Oilphase-DBR) | Huo, Zhongxin (Shell Global Solutions) | Broze, George (Shell Global Solutions) | Howe, Richard (Shell Exploration & Production) | Lagers, Kees (Shell Exploration & Production)
Abstract Shell Exploration & Production Company has been operating fields producing asphaltenic fluids in the Gulf of Mexico (GOM) for several years and had previously been unable to accurately predict the extent and location of asphaltene deposition. As a result, well bores and subsea flowlines have in some cases been plugged whereas in other cases it is likely that inhibitor injections have been unnecessarily employed. In this study, a flow-through high-pressure deposition cell was used to measure the deposition rate of asphaltenes from a problematic field in the GOM under realistic conditions of pressure, temperature and composition. The impacts of shear (corresponding to the production rate in the field), residence time of the fluid in the cell, pressure, and chemical injection on the asphaltene deposition rate were investigated. Finally, the importance of these measurements for field production is discussed. Introduction As production from conventional onshore and shallow off-shore fields decline, deepwater production will continue to increase in importance. Large pressure and temperature drops often encountered in deepwater production systems increase the risk of asphaltene precipitation and deposition. Commingling of incompatible fluids and gas lift may also destabilize the system. The large capital and operating costs associated with prevention and remediation of deposits has created the need for improved methods to measure and model for optimization of system design and operations while still ensuring minimized risk of deposition issues. The techniques applied for prevention of asphaltene deposition in the field include retaining the operating pressure above the detected onset pressure, increasing the production rate, decreasing the residence time of the fluid in pipeline and chemical injection. In the absence of lab-scale measurement of asphaltene deposition, however, the operators may not be able to apply such techniques properly and deposition may happen unexpectedly. In other cases, despite a system incurring asphaltene precipitation under operating conditions of temperature and pressure, asphaltene deposition may not happen due to other factors such as shear, kinetics, and physiochemical characteristics of asphaltenes and pipeline surface. The high-pressure deposition cell, designed based on the Taylor-Couette flow principles, is a tool for generating organic solids deposits under a wide variety of operating conditions. This equipment in its batch mode (closed system) has been used to measure the deposition rate of waxes and asphaltenes from live fluids under turbulent flow conditions (Zougari et al., 2005, 2006; Akbarzadeh and Zougari, 2008; Akbarzadeh et al., 2008a, 2008b). However, the experimental measurements have been inconclusive for asphaltene deposition from crudes with low asphaltene content. For these fluids, the amount of deposit obtained from a batch experiment, with 150 cm3 fluid in the cell, is often very small (less than 15 mg). This results in a large relative uncertainty in the measured data, and therefore interpretation is difficult. The other problem with deposition in a batch system is depletion. A decrease in the amount of depositing asphaltenes in the cell over a short period of time (typically two hours) will yield averaged deposition rates that are not representative of those in the field.
Peyman, Pourafshary (School of Mining and Geosciences, Nazarbayev University, Nur Sultan, Kazakhstan) | Majid, Zamani (Institute of Petroleum Engineering, University of Tehran, Tehran, Iran) | Muhammad, Hashmet Rehan (School of Mining and Geosciences, Nazarbayev University, Nur Sultan, Kazakhstan)
Prediction of asphaltene deposition in production system and design of production parameters adequately to control this issue is inevitable. We presented a transient model to predict asphaltene deposition along the tubing string in the production system. An accurate two-phase fluid flow model was coupled with a solid asphaltene precipitation model and a sub-layer particle deposition model in turbulent flow with the ability to predict the deposition of particles in vertical surfaces. Our procedure shows good agreement with the experimental work previously done to measure the rate of deposition of flocculated asphaltene particles via an accurate thermal apparatus at different temperatures and flow rates. The developed model was used to simulate the deposition of asphaltene in a real field. The results suggest that even with high flow rates, the deposited asphaltene caused a 2.5% reduction in wellhead pressure after 30 days of production. The developed model can predict the transient location of the asphaltene, onset pressure, and the profile of the deposited asphaltene in a wellbore versus time. In practice, the proposed model can be used for analysis of different production scenarios in a given well to minimize the possibility and extent of asphaltene deposition and enhance the production rate.
Production of heavy oils and paraffinic crude reserves Asphaltenes are a solubility class and are usually often results in the deposition of organic solids, typically defined as the fraction of a crude oil that precipitates in an waxes or asphaltenes. The organic deposits can reduce aliphatic solvent (typically n-pentane or n-heptane) yet the productivity of the reservoir as well as foul piping and remains soluble in toluene. Asphaltenes are the most surface equipment. Current chemical and mechanical aromatic and polar fraction of crude oil and have the methods for treating deposition are only partially effective largest heteroatom and metal content. They consist of a partly because the deposition process is poorly variety of molecular species with molar masses of at least understood.
Abstract Particle deposition is a complex problem in oil fields which affects all aspects of petroleum production, processing, and transportation. Asphaltene deposition has been repeatedly reported in various oil fields with interest on how it impacts the development of a reservoir. In many of the reported cases, it has been indicated that asphaltene deposition damages the wellbore and production facilities more severely than the formation. A great deal of research has been conducted to study the phase behavior and dynamic aspect of asphaltene deposition. However, there is a lack of comprehensive integrated modeling of asphaltene deposition in the wellbore during the multiphase fluid flow. In this paper, we present an implementation of asphaltene precipitation and deposition models into a thermal, multiphase, multi-component wellbore simulator that can be coupled with a compositional reservoir simulator. A key contribution of this work is the development of a simulator for predicting the detrimental effects of asphaltene in a well. Simulation results can show where and when the presence of asphaltene particles severely damages the efficiency and the productivity of the wells. This prediction is highly crucial if it is aimed to control the well performance and to optimize productivity.
Abdallah, Dalia (Abu Dhabi Company for Onshore Oil Operations) | Al-Basry, Ali (Abu Dhabi Company for Onshore Oil Operations) | Zwolle, Simon (Abu Dhabi Company for Onshore Oil Operations) | Grutters, Mark (Shell) | Huo, Zhongxin (Shell) | Stankiewicz, Artur (Schlumberger)
Abstract Asphaltene is the heavy component of a crude oil that constitutes a potential problem because of its tendency to precipitate and deposit causing blockage in tubulars, pipelines and surface facilities leading to decline in oil production. There are a number of wells affected with asphaltene in an onshore field in Abu Dhabi and this is likely to increase in the future with the implementation of Artificial Lift (AL) and HC/CO2 gas injection for EOR. Mitigation strategies in the field have been concentrating on design of remedial solvent treatments in combination with mechanical methods for removal of deposits. The company’s approach has been shifting in dealing with asphaltenes from reactive to proactive by conducting studies to: understand asphaltene stability in the different fluids, model the behavior across the whole field, look at the effect of HC/CO2 gas injection on asphaltene stability and finally develop optimal preventative techniques to reduce treatment costs. The study in this onshore field in Abu Dhabi was conducted on oils collected from different zones. The first part of the study involved analysis of different stock tank oil properties, e.g. API, Sulfur content, Nickel content, asphaltene content and viscosity to look for correlations that can help in identifying the problematic areas in the field. The second part of the study involved asphaltene stability screening tests, e.g. SARA screen, to determine whether the fluids from the different zones are stable or unstable with respect to asphaltene. Live-oil depressurization experiments were conducted on selected wells to determine the Asphaltene Onset Pressure (AOP) at different production conditions using solids detection system with Near Infra-Red (NIR) and High Pressure Microscopy (HPM) for visual confirmation of asphaltene particles. The data from the live-oil testing was then used to calibrate Shell’s thermodynamic model which was then used to investigate the effect of changes in process conditions on asphaltene stability phase envelopes. Results of thermodynamic modeling can be applied on the full field which will aid in developing appropriate inhibition and remediation strategies to deal with the asphaltene challenges.