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Asphaltene deposition is one of the key technical problems in the safe production and transportation of deepwater asphalt base crude oil. This paper analyzes the asphaltene deposition condition and its existence in deepwater crude oil pipeline system by theoretical and experimental study. According to the thermodynamic behavior of crude oil system, the prediction model of its asphaltene deposition conditions is established, and combined with the pressure and temperature drop analysis of deepwater crude oil pipeline system, the prediction method of asphaltene deposition amount and location in deepwater pipelines is preliminarily formed. This study lays a foundation for further study on the flow assurance of deepwater asphalt base crude oil transportation system.
Asphaltene deposition in deepwater pipeline is an important technical problem in the present petroleum industry. Due to the challenging deepwater environments, especially low temperature, adhesion of asphalt base crude oil is strong and liquidity is poor (Sara and Abbas, 2013). Once solid blockage appears in deepwater pipeline, it is very difficult to resume production and remediation cost is extremely high, which presents a high risk to oil production.
According to the special environment of deepwater oil pipeline, the asphaltene deposition condition and its existence in the deepwater oil pipeline system are analyzed based on the changes of pressure and composition of crude oil system. Taking K96 crude oil, KD32 emulsified oil and dewatered oil as the research objects, the rheological properties and corresponding microscopic shapes of the oil samples before and after adding n-heptane are tested and analyzed by using rheology and image analysis technology. Meanwhile, the mathematical model of asphaltene deposition in deepwater crude oil pipeline is established to predict the asphaltene deposition condition, and the prediction method of the asphaltene deposition amount and location in deepwater oil pipeline is initially formed. This is not only necessary but also very challenging to the flow assurance of deepwater asphalt base crude oil transportation system.
Scale deposition in perforations and tubular goods has been a problem for decades in the oil industry. Years have been spent in research and in somewhat futile attempts to solve this problem. Classic treatment is with a fluid, usually an acid, which is designed based on the mineralogical content of the scale. Complicating these efforts is the relationship of down-hole bacteria to scale deposition. The above mentioned treatments do not address the presence of bacteria. The ability of organisms to thrive in hostile environments is sometimes difficult to overcome and the number of biocides on the market today attests to this. The problems caused by these scale deposits have cost producers millions of dollars and have been known to change sweet oil to sour in whole fields. Also, much money has been spent for cathodic protection and other corrosion inhibition treatments when the major cause of tubular corrosion may have been biological activity.
Typical scale identification consists of determination of constituents by chemical means, X-ray or microscopic analysis, and acid solubility tests. This series of tests is necessary for the design of scale removal treatments, but does not account for the causes of scaling. Computer programs which determine the scaling tendency of waters give an insight into the cause of scaling. However, none of these tests can show the influence of biological activity. In order to provide a more thorough analysis of the cause of scaling, the use of epifluorescence microscopy has been added to the testing scheme. Bacterial calls from a scale and/or water are dyed and their fluorescence observed microscopically. The lack of fluorescence indicates no biological activity. The information gained from this microscopic technique is then used to modify removal treatments and to design treatments to help prevent further deposition.
This paper will discuss (1) epifluorescence as a scale testing technique, (2) well conditions that contribute to bacterial growth, (3) areas in the Rocky Mountains where bacterial scaling is prevalent, and (4) removal and inhibition treatments.
It is accepted that several major oil production problems can stem from the influence of sulfate-reducing problems can stem from the influence of sulfate-reducing bacteria (SRB). There is some debate as to whether SRB are indigenous to oil-bearing formations or whether they are only introduced with the use of surface or ground water during drilling and treatment procedures. Regardless of origin, the effects of SRB include (1) the corrosion of iron in the absence of air, (2) souring of oil by H2S generation, and (3) precipitation of amorphous ferrous sulfide. It is this latter problem that will be addressed in this paper.
The species of SRB that have been most widely studied in relationship to oil field problems are Desulfovibrio, Desulfotomaculum and Desulfobulbus. SRB are not homogeneous and this diversity can be appreciated when looking at size, shape, growing environments, food sources, and adaptability to environmental changes. Table 1 illustrates this wide range of characteristics. The consequence of this diversity is that the actual identification of specie and culture tenting of SRB from oil well waters may be a moot point with regard to treatment. Many SRB which produce H2S and precipitate ferrous sulfide reside in sessile environments within a protective anionic polysaccharide or in anaerobic microniches. These would not be available for testing or culturing from a water sample.
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.