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Cem Sarica - One of the best experts on this subject based on the ideXlab platform.
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tulsa university paraffin deposition projects
Other Information: PBD: 1 Jun 2004, 2004Co-Authors: Cem Sarica, Michael VolkAbstract:As oil and gas production moves to deeper and colder water, subsea Multiphase production systems become critical for economic feasibility. It will also become increasingly imperative to adequately identify the conditions for paraffin precipitation and predict paraffin deposition rates to optimize the design and operation of these multi-phase production systems. Although several oil companies have paraffin deposition predictive capabilities for single-phase oil flow, these predictive capabilities are not suitable for the Multiphase flow conditions encountered in most flowlines and wellbores. For deepwater applications in the Gulf of Mexico, it is likely that Multiphase production streams consisting of crude oil, produced water and gas will be transported in a single Multiphase Pipeline to minimize capital cost and complexity at the mudline. Existing single-phase (crude oil) paraffin deposition predictive tools are clearly inadequate to accurately design these Pipelines, because they do not account for the second and third phases, namely, produced water and gas. The objective of this program is to utilize the current test facilities at The University of Tulsa, as well as member company expertise, to accomplish the following: enhance our understanding of paraffin deposition in single and two-phase (gas-oil) flows; conduct focused experiments to better understand various aspects of deposition physics; and, utilize knowledge gained from experimental modeling studies to enhance the computer programs developed in the previous JIP for predicting paraffin deposition in single and two-phase flow environments. These refined computer models will then be tested against field data from member company Pipelines.
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Severe Slugging Attenuation for Deepwater Multiphase Pipeline and Riser Systems
Spe Production & Facilities, 2003Co-Authors: J.Ø. Tengesdal, Cem Sarica, L.g. ThompsonAbstract:Exploitation of offshore petroleum reservoirs has recently moved to ever-increasing water depths. Production from fields in water deeper than 1800 m is now a reality. The use of long deepwater risers that conduct production from multiple wellheads on the sea-floor to the surface predisposes the system to severe slugging in the riser for a wide range of flow rates and seabed topography. When one considers the length of the deepwater risers, the problem is expected to be more severe than in production systems installed in shallower waters. Severe slugging could occur at high pressure, with the magnitude of the pressure fluctuations so large as to cause a shorter natural flow period with subsequent consequences, such as premature field abandonment, loss of recoverable reserves, and earlier-than-planned deployment of boosting devices. In this study, a novel idea to lessen or eliminate severe slugging in Pipeline/riser systems has been thoroughly investigated. This idea was first proposed by Barbuto 1 and later developed independently by Sarica and Tengesdal. 2 The principle of the technique is to transfer Pipeline gas to the riser at a point above the riser base. The transfer process will reduce both the hydrostatic head in the riser and the pressure in the Pipeline, consequently lessening or eliminating severe slugging by maintaining steady-state two-phase flow in the riser. An experimental study has been conducted with a 7.62-cm-inside-diameter (ID) riser (14.63 m high) and Pipeline (19.81 m long) system. A broad range of data was collected from the facility in both the severe slugging and stable regions. It was found that the severe slugging models currently available do not predict the region accurately for larger-diameter pipes. Data acquired with the external gas bypass have proved the proposed elimination technique.
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Severe Slugging Attenuation for Deepwater Multiphase Pipeline and Riser Systems
SPE Production & Facilities, 2003Co-Authors: J.Ø. Tengesdal, Cem Sarica, Leslie ThompsonAbstract:Summary Exploitation of offshore petroleum reservoirs has recently moved to ever-increasing water depths. Production from fields in water deeper than 1800 m is now a reality. The use of long deepwater risers that conduct production from multiple wellheads on the seafloor to the surface predisposes the system to severe slugging in the riser for a wide range of flow rates and seabed topography. When one considers the length of the deepwater risers, the problem is expected to be more severe than in production systems installed in shallower waters. Severe slugging could occur at high pressure, with the magnitude of the pressure fluctuations so large as to cause a shorter natural flow period with subsequent consequences, such as premature field abandonment, loss of recoverable reserves, and earlier-than-planned deployment of boosting devices. In this study, a novel idea to lessen or eliminate severe slugging in Pipeline/riser systems has been thoroughly investigated. This idea was first proposed by Barbuto1 and later developed independently by Sarica and Tengesdal.2 The principle of the technique is to transfer Pipeline gas to the riser at a point above the riser base. The transfer process will reduce both the hydrostatic head in the riser and the pressure in the Pipeline, consequently lessening or eliminating severe slugging by maintaining steady-state two-phase flow in the riser. An experimental study has been conducted with a 7.62-cm-inside- diameter (ID) riser (14.63 m high) and Pipeline (19.81 m long) system. A broad range of data was collected from the facility in both the severe slugging and stable regions. It was found that the severe slugging models currently available do not predict the region accurately for larger-diameter pipes. Data acquired with the external gas bypass have proved the proposed elimination technique. Introduction Severe slugging can occur in two-phase flow systems in which a Pipeline segment with a downward inclination angle is followed by another segment/riser with an upward inclination angle. At relatively low gas and liquid flow rates, liquid can accumulate at the riser base of such a system, blocking the gas flow. This will result in an increasing liquid level in the riser until the liquid reaches the riser top. Simultaneously, gas in the downward-inclined section will be compressed. When the gas pressure in the Pipeline has increased enough to counter the hydrostatic head of the liquid column, the gas will expand and push the liquid column violently out of the riser into the separator. Severe slugging will cause periods of no liquid and gas production in the separator followed by very high liquid and gas flow rates. The resulting large pressure and flow-rate fluctuations are highly undesirable; sudden surges in liquid production could cause overflow and shutdown of the separator. Fluctuations in gas production could result in operational and safety problems during flaring, and the high pressure fluctuations could negatively impact the field's production performance and ultimately lead to a reduction in recoverable reserves. Currently, there are three basic elimination methods that have been proposed - backpressure increase, gas lift, and choking. All other proposed techniques are based on these three methods. The backpressure-increase method eliminates severe slugging by increasing the system pressure, thereby significantly reducing production capacity. In gas lifting, external gas is injected into either the riser or the Pipeline at the riser bottom to reduce the hydrostatic head in the riser or to increase the gas flow rate in the Pipeline. Gas-lift equipment requires a large footprint on the platform and large amounts of gas to accomplish the elimination. The operational cost of gas lifting can be very significant. Choking increases the backpressure in proportion to the velocity increase in the riser. If the movement of the gas in the riser is stabilized before reaching the choke, steady flow will occur after a short flow period. The stabilization requires very careful choking to ensure minimum backpressure. Although there are several other methods proposed to eliminate severe slugging, their working principles are similar to or derivatives of the three methods described previously. Sarica and Tengesdal2 presented a literature review on the topic of severe slugging. Considering the dimensions of deepwater Pipeline/riser systems, the severe slugging phenomenon is expected to be more pronounced, with a possible occurrence at considerably higher system operating pressures than in comparable production systems at shallower depths. Therefore, system design and the methodology used to control or eliminate severe slugging become very crucial when considering the safety of the operation and the limited space available on the platform. Moreover, the cost of a deepwater production/riser system is expected to be very high, and the remediation efforts of any reliability failures can be cost-prohibitive. Cost figures as high as U.S. $30 to 50 million for typical systems of 350- to 500-m water depths have been reported in the literature.3 The applicability of current practices for predicting and eliminating severe slugging in deepwater developments is very much in question. Different techniques can be suitable for different types of problems and production systems. An assessment of the different, existing, applicable elimination techniques has been presented earlier by Sarica and Tengesdal.2 Although different severe-slugging-elimination techniques are reported in the literature,2 none have been tested and verified for elimination of severe slugging in deep waters. Drastic differences in capital and operational expenditures among the different techniques have also been reported. Some of the promising concepts, such as foaming and self-lifting, are still conceptual and need to be developed and verified. In this study, the self-lifting concept has been thoroughly investigated.
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TULSA UNIVERSITY PARAFFIN DEPOSITION PROJECTS
2003Co-Authors: Michael Volk, Cem SaricaAbstract:As oil and gas production moves to deeper and colder water, subsea Multiphase production systems become critical for economic feasibility. It will also become increasingly imperative to adequately identify the conditions for paraffin precipitation and predict paraffin deposition rates to optimize the design and operation of these Multiphase production systems. Although several oil companies have paraffin deposition predictive capabilities for single-phase oil flow, these predictive capabilities are not suitable for the Multiphase flow conditions encountered in most flowlines and wellbores. For deepwater applications in the Gulf of Mexico, it is likely that Multiphase production streams consisting of crude oil, produced water and gas will be transported in a single Multiphase Pipeline to minimize capital cost and complexity at the mudline. Existing single-phase (crude oil) paraffin deposition predictive tools are clearly inadequate to accurately design these Pipelines because they do not account for the second and third phases, namely, produced water and gas. The objective of this program is to utilize the current test facilities at The University of Tulsa, as well as member company expertise, to accomplish the following: enhance our understanding of paraffin deposition in single and two-phase (gas-oil) flows; conduct focused experiments to better understand various aspects ofmore » deposition physics; and, utilize knowledge gained from experimental modeling studies to enhance the computer programs developed in the previous JIP for predicting paraffin deposition in single and two-phase flow environments. These refined computer models will then be tested against field data from member company Pipelines. The following deliverables are scheduled during the first three projects of the program: (1) Single-Phase Studies, with three different black oils, which will yield an enhanced computer code for predicting paraffin deposition in deepwater and surface Pipelines. (2) Two-Phase Studies, with a focus on heat transfer and paraffin deposition at various pipe inclinations, which will be used to enhance the paraffin deposition code for gas-liquid flow in pipes. (3) Deposition Physics and Water Impact Studies, which will address the aging process, improve our ability to characterize paraffin deposits and enhance our understanding of the role water plays in paraffin deposition in deepwater Pipelines. As in the previous two studies, knowledge gained in this suite of studies will be integrated into a state-of-the-art three-phase paraffin deposition computer program.« less
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Severe Slugging Attenuation for Deepwater Multiphase Pipeline and Riser Systems
All Days, 2002Co-Authors: J.Ø. Tengesdal, Cem Sarica, L.g. ThompsonAbstract:Abstract Recently, exploitation of offshore petroleum reservoirs has moved to ever increasing water depths. Production from fields in water deeper than 1800 m is now a reality. The use of long deep-water risers that conduct production from multiple wellheads on the sea floor to the surface predisposes the system to severe slugging in the riser for a wide range of flow rates and seabed topography. Considering the length of the deep-water risers, the problem is expected to be more severe than in production systems installed in shallower waters. Severe slugging could occur at high pressure, with the magnitude of the pressure fluctuations so large as to cause a shorter natural flow period with subsequent consequences such as premature field abandonment, loss of recoverable reserves and earlier-than-planned deployment of boosting devices. In this study, a novel idea to lessen or eliminate severe slugging in Pipeline-riser systems has been thoroughly investigated. This idea was first proposed by Barbuto3, and later developed independently by Sarica and Tengesdal9. The principle of the technique is to transfer the Pipeline gas to the riser at a point above the riser-base. The transfer process will reduce both the hydrostatic head in the riser and the pressure in the Pipeline, consequently lessening or eliminating the severe slugging by maintaining the steady-state two-phase flow in the riser. An experimental study has been conducted using a 7.62 cm. inner diameter riser (14.63 m high) and Pipeline (19.81 m long) system. A broad range of data was collected from the facility both in the severe slugging and stable regions. It was found that currently available severe slugging models do not predict the severe slugging region accurately for larger diameter pipes. Data acquired with the external gas bypass have proven the proposed elimination technique. Introduction Severe slugging can occur in two-phase flow systems where a Pipeline segment with a downward inclination angle is followed by another segment/riser with an upward inclination angle. For such a system, at relatively low gas and liquid flow rates, liquid can accumulate at the riser base, blocking the gas flow. This will consequently result in an increasing liquid level in the riser until the liquid reaches the riser top. Simultaneously, gas in the downward inclined section will be compressed. When the gas pressure in the Pipeline has increased enough to counter the hydrostatic head of the liquid column, the gas will expand and push the liquid column violently out of the riser into the separator. Severe slugging will cause periods of no liquid and gas production in the separator followed by very high liquid and gas flow rates. The resulting large pressure and flow rate fluctuations are highly undesirable; sudden surges in liquid production could cause overflow and shut down of the separator. Fluctuations in gas production could result in operational and safety problems during flaring, and the high pressure fluctuations could impact negatively on the field's production performance, and ultimately lead to a reduction in recoverable reserves. Currently, there are three basic elimination methods that have been proposed, namely, backpressure increase, gas lift, and choking. All other proposed techniques are based on these three elimination methods. The backpressure increase method eliminates severe slugging by increasing the system pressure, and thereby significantly reducing the production capacity. In gas lifting, external gas is injected either into the riser or Pipeline at the riser bottom to reduce the hydrostatic head in the riser or increase the gas flow rate in the Pipeline. Gas-Lift equipment requires a large footprint on the platform and large amounts of gas to accomplish the elimination. The operational cost of gas lifting can be very significant.
Michael Volk - One of the best experts on this subject based on the ideXlab platform.
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tulsa university paraffin deposition projects
Other Information: PBD: 1 Jun 2004, 2004Co-Authors: Cem Sarica, Michael VolkAbstract:As oil and gas production moves to deeper and colder water, subsea Multiphase production systems become critical for economic feasibility. It will also become increasingly imperative to adequately identify the conditions for paraffin precipitation and predict paraffin deposition rates to optimize the design and operation of these multi-phase production systems. Although several oil companies have paraffin deposition predictive capabilities for single-phase oil flow, these predictive capabilities are not suitable for the Multiphase flow conditions encountered in most flowlines and wellbores. For deepwater applications in the Gulf of Mexico, it is likely that Multiphase production streams consisting of crude oil, produced water and gas will be transported in a single Multiphase Pipeline to minimize capital cost and complexity at the mudline. Existing single-phase (crude oil) paraffin deposition predictive tools are clearly inadequate to accurately design these Pipelines, because they do not account for the second and third phases, namely, produced water and gas. The objective of this program is to utilize the current test facilities at The University of Tulsa, as well as member company expertise, to accomplish the following: enhance our understanding of paraffin deposition in single and two-phase (gas-oil) flows; conduct focused experiments to better understand various aspects of deposition physics; and, utilize knowledge gained from experimental modeling studies to enhance the computer programs developed in the previous JIP for predicting paraffin deposition in single and two-phase flow environments. These refined computer models will then be tested against field data from member company Pipelines.
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TULSA UNIVERSITY PARAFFIN DEPOSITION PROJECTS
2003Co-Authors: Michael Volk, Cem SaricaAbstract:As oil and gas production moves to deeper and colder water, subsea Multiphase production systems become critical for economic feasibility. It will also become increasingly imperative to adequately identify the conditions for paraffin precipitation and predict paraffin deposition rates to optimize the design and operation of these Multiphase production systems. Although several oil companies have paraffin deposition predictive capabilities for single-phase oil flow, these predictive capabilities are not suitable for the Multiphase flow conditions encountered in most flowlines and wellbores. For deepwater applications in the Gulf of Mexico, it is likely that Multiphase production streams consisting of crude oil, produced water and gas will be transported in a single Multiphase Pipeline to minimize capital cost and complexity at the mudline. Existing single-phase (crude oil) paraffin deposition predictive tools are clearly inadequate to accurately design these Pipelines because they do not account for the second and third phases, namely, produced water and gas. The objective of this program is to utilize the current test facilities at The University of Tulsa, as well as member company expertise, to accomplish the following: enhance our understanding of paraffin deposition in single and two-phase (gas-oil) flows; conduct focused experiments to better understand various aspects ofmore » deposition physics; and, utilize knowledge gained from experimental modeling studies to enhance the computer programs developed in the previous JIP for predicting paraffin deposition in single and two-phase flow environments. These refined computer models will then be tested against field data from member company Pipelines. The following deliverables are scheduled during the first three projects of the program: (1) Single-Phase Studies, with three different black oils, which will yield an enhanced computer code for predicting paraffin deposition in deepwater and surface Pipelines. (2) Two-Phase Studies, with a focus on heat transfer and paraffin deposition at various pipe inclinations, which will be used to enhance the paraffin deposition code for gas-liquid flow in pipes. (3) Deposition Physics and Water Impact Studies, which will address the aging process, improve our ability to characterize paraffin deposits and enhance our understanding of the role water plays in paraffin deposition in deepwater Pipelines. As in the previous two studies, knowledge gained in this suite of studies will be integrated into a state-of-the-art three-phase paraffin deposition computer program.« less
Sigurd Skogestad - One of the best experts on this subject based on the ideXlab platform.
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ACC - ℒ 1 adaptive anti-slug control
2017 American Control Conference (ACC), 2017Co-Authors: Sveinung Johan Ohrem, Christian Holden, Esmaeil Jahanshahi, Sigurd SkogestadAbstract:In many Multiphase Pipeline-riser systems, anti-slug control is necessary to ensure steady and optimal operation. In this paper, we propose using an ℒ 1 adaptive controller as an augmentation to standard PI control to stabilize the desired non-slugging flow regime. The ℒ 1 adaptive controller is designed based on a model identified from an experimental closed-loop step test. The proposed design involves fewer tuning parameters compared to other adaptive control methods and it does not need any observer. We have tested the controller by simulations in both MATLAB and OLGA, and by experiments in a small-scale laboratory. The results show that the proposed solution can stabilize the process outside the stability region of the traditional PI controller.
Abelindo A. De Oliveira - One of the best experts on this subject based on the ideXlab platform.
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Pressure Based Leak Detection for Pipelines, Implemented at Business Unit of Production and Exploration of Petrobras in Rio Grande do Norte and Ceará
2004 International Pipeline Conference Volumes 1 2 and 3, 2004Co-Authors: Diane J. Hovey, Tuerte A. Rolim, Abelindo A. De OliveiraAbstract:This paper presents the experiences of the Petrobras Business Unit (UN-RNCE), located in Rio Grande del Norte state of Brazil, during the installation and startup of a Pipeline leak detection system. The application involves nine Multiphase oil Pipelines that link several productions facilities together over a total distance of 450-Km. Prior to the selection and installation of this leak detection system a significant Pipeline accident resulted in the pollution of Guanabara bay. The leak was not detected by the existing monitoring equipment because of the two phase and Multiphase Pipeline characteristics. The UN-RNCE decided to install EFA Technologies, Inc., Pressure Point Analysis (PPA) ™ technology in order to detect leaks. It is a sophisticated statistical method for leak detection, uses very simple field instrumentation, which facilitates ease of installation and maintenance. However, in order to get the best performance out of the system, it is necessary to understand how the Pipeline control processes operate and to have a fast, reliable SCADA system for long distance communication. This paper includes the test results, conclusions and the recommendations to expand the system.Copyright © 2004 by ASME
Juyoung Shin - One of the best experts on this subject based on the ideXlab platform.
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experimental measurement of the induction time of natural gas hydrate and its prediction with polymeric kinetic inhibitor
Chemical Engineering Science, 2014Co-Authors: Seongpil Kang, Juyoung ShinAbstract:Abstract It is assumed that the heterogeneous nucleation of hydrates in the upstream oil and gas industry occurs, which would block the fluid flow transportation, when produced fluids (oil/gas/water) in a Multiphase Pipeline enter the hydrate stability temperature and pressure conditions. This has led to the development of flow assurance strategies to operate outside the hydrate stability region. The past flow loop data on oil and gas systems suggest that hydrates usually require some sub-cooling (on the order of 3 K or so) to be formed and it takes a while. Thus, there are two different ways to transport the fluid; firstly by staying outside of the hydrate-stable region or secondly transport the fluid in the hydrate stable region before hydrate formation started. Thus it would be also possible to transport the fluid in hydrate stability region before hydrate formation started. To achieve this goal, three different kinds of inhibitors are used: (1) thermodynamic inhibitors, (2) kinetic inhibitors, and (3) anti-agglomerants. Thermodynamic inhibitors would change the equilibrium condition of gas hydrates, while kinetic inhibitors would change the induction time and anti-agglomerants inhibit the crystal agglomeration. In this work, two kinetic inhibitors (poly N-vinylpyrrolidone, PVP and poly N-vinylcaprolactam, PVCap) were tested and a kinetic model to predict the induction time with an inhibitor was developed using the Freundlich adsorption isotherm. Currently, the model can be used in limited conditions such as specific gas composition, temperature range and polymeric inhibitors. However, this model has a good potential to predict the minimum concentration of inhibitor to prevent hydrate plugging at various temperatures and pressure conditions.
