OTC 24396

Prevention, Management, and Remediation Approaches for Gas Hydrates in the Flow Assurance of Oil/Gas Flowlines A. K. Sum, Colorado School of Mines

Copyright 2013, Offshore Technology Conference This paper was prepared for presentation at the Offshore Technology Conference Brasil held in Rio de Janeiro, Brazil, 29–31 October 2013. This paper was selected for presentation by an OTC program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Offshore Technology Conference and are subject to correction by the author(s). The material does not necessarily reflect any position of the Offshore Technology Conference, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Offshore Technology Conference is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of OTC copyright.

Abstract Gas hydrates pose the major flow assurance problem in the production and transportation of oil and gas. As production moves to hasher environment (deeper water, longer tiebacks, more produced water), preventing, managing, and remediation of gas hydrates are central for safe and continuous operation. In this paper, we will provide an overview of the approaches used in the prevention, management, and remediation of gas hydrates in oil/gas flowlines. The approaches developed are based on the research performed at the Center for Hydrate Research at the Colorado School of Mines over several decades. The paper will discuss how hydrate formation conditions is estimated for prevention, how hydrates formation occurs in flowlines for management, and how hydrate dissociation occurs for remediation. The understanding of hydrate formation in multiphase flow is an evolving area, even though significant knowledge has been gained over the years in terms of fundamental processes for hydrate nucleation, growth, agglomeration, deposition, and plugging. Each of these areas is part of a comprehensive model describing the various stages of hydrate formation. We will overview the process for hydrate formation in oil-dominated, water-dominated, and gas-dominated systems, and the tools developed that can be applied to addressing hydrates in the flow assurance of oil/gas flowlines. Introduction Gas hydrates play a significant role in the flow assurance of oil and gas flowlines, posing one of the most serious problems relative to the formation and deposition of other solids (e.g., wax, asphaltenes, scale, etc.). The formation of gas hydrates in flowlines can be not only fast, but also in large volumes, causing unexpected operational problems.1 Industry has traditionally taken the approach of preventing gas hydrates from forming in flowlines by injection of so-called thermodynamic inhibitor, THI (e.g., methanol, monoethylene glycol, ethanol), which inhibits hydrate formation in the free water phase. As seen in Figure 1, in this approach the THI shifts the hydrate equilibrium curve to more severe temperature and pressure conditions, thus allowing the flowline to operate outside the hydrate stability region. While effective in preventing hydrate formation, the costs and quantity of chemical required can be significant.2 Over the last two decades, industry has looked for an alternative approach to the complete prevention of gas hydrates in flowlines by shifting to a management strategy of hydrates, that is, to allow hydrates to form in flowlines but prevent their agglomeration to form a blockage.3 Such a strategy would allow industry to tolerate hydrates in the flowlines and reduce the cost and quantity of chemicals used in their operations. Using this approach, it is therefore important to have a good understanding how hydrates are forming, agglomerating, depositing, and jamming a flowline, so that one can assess the risk of hydrates in the flowlines and the potential for a blockage to form. This approach has been implemented to some extent in the last decade in industry with the use of anti-agglomerants (AAs) and low-dosage hydrate inhibitors (LDHIs). There cases where the formation and blockage of flowlines with hydrates is inevitable, due to unplanned shutdown or abnormal operating conditions originating from equipment malfunction. In these cases, industry must be able to remove the hydrate blockage(s) in the flowlines before normal operation can be resumed. The removal of hydrate blockages can be a tenuous process as the dislodging of the hydrate blockage can generate a projectile in the flowline.

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This paper will give an overview of the tools developed at the Center for Hydrate Research (CHR) at the Colorado School of Mines (CSM) that can help the flow assurance engineer to understand the prevention, management, and remediation of hydrates in multiphase oil and gas flowlines. In the management of hydrates, a understanding of the mechanisms for hydrate formation and accumulation in multiphase flowlines is needed. These mechanisms are evolving and a description of the main components in oil-dominated, water-dominated, and gas-dominated systems is also presented.

Figure 1. Example schematic of a pressure-temperature trace for a field and the corresponding hydrate equilibrium boundaries with and without methanol as THI in the free water phase. Hydrate Prevention The conservative approach for dealing with hydrates in the oil and gas industry is to not allow the formation of hydrates in multiphase oil and gas flowlines. This approach requires knowledge of the hydrate formation boundary for the hydrocarbon system including the range of temperature and pressure conditions the flowline is exposed to, e.g., from the wellhead to the platform, as shown in Figure 1. The prevention of hydrates is done with the injection of sufficient amounts of thermodynamic inhibitors (e.g., methanol, ethanol, monoethylene glycol) so the thermodynamic conditions for hydrates to form are shifted to more sever conditions (lower temperature and high pressure), as illustrated in Figure 1. One tool to determine the hydrate formation conditions and the required amount of inhibitor is CSMGem,4 which stands for Colorado School of Mines Gibbs Energy Minimization. CSMGem is a user-friendly tool that allows one to input a specific hydrocarbon mixture and obtain hydrate equilibrium boundary with and without thermodynamic inhibitors. The output of CSMGem would result in a plot very similar to Figure 1. Other tools similar to CSMGem exist, including DBR Hydrates, MultiFlash, and PVTSim, but unlike these other tools, CSMGem is specifically focused on hydrates and it can be readily obtained through the Center for Hydrate Research. The strength of CSMGem is that it was developed to consider a wide range of experimental data on hydrate phase equilibrium, and it has been tested by many users and companies over a number of years. The limitations of CSMGem are that it does not offer a selection of equation of states to choose from, and the convergence of the calculations for systems containing high salt (>~5 wt%) can be problematic. CSMGem has also the ability to perform flash calculations to determine the phases at equilibrium under any given condition, as well as determine the conditions for compression/expansion of fluids. The prevention strategy for hydrates is well established and widely used in industry, as the thermodynamics of the systems are well defined and understood. Among the thermodynamic inhibitors, methanol has been proven to be the most effective on a per weight and cost basis. Monoethylene glycol (MEG) is more widely used for gas systems, and ethanol seems to be the predominant inhibitor for the fields in Brazil. Hydrate Management The strategy for hydrate management in multiphase oil and gas flowlines is a newer concept and of course one with some risk involved, that is, since hydrates are allowed to form in a controlled matter, there is always a chance that hydrate blockages may eventually form, jeopardizing the continual operational. The key in hydrate management is to prevent agglomeration of

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hydrates, and this is typically accomplished by the injection of chemicals called anti-agglomerants (AAs), which have the function as their name states. As long as hydrates are kept dispersion in the fluid phase, the risk of hydrate blockage formation is minimized. To apply the hydrate management strategy, one must have a very good understanding of the process for hydrate formation, agglomeration, and accumulation/deposition in flowlines. This understanding is much more difficult and complex than the hydrate prevention approach where only the thermodynamics of the system is needed. At the CHR, our research over the last two decades has been focused on developing the understanding for hydrate formation under transient conditions to specifically address the hydrate management strategy. To accomplish this, we have developed conceptual models and subsequent gather data to build physical models that describe each of the processes involved in the formation, agglomeration, and accumulation of hydrates in multiphase flow for oil-dominated, water-dominated, and gas-dominated systems. The formation and transport of hydrate in flowlines are perhaps one of the most complex multiphase flow problems, involving gas, liquid hydrocarbon, water, and hydrates as solids. One conceptual view (based on the work at CSM over decades of research and input from industry leaders in the field) on how hydrates may form and agglomerate to a blockage in flowlines containing gas, oil, and water is shown in Figure 2, which illustrates the following major processes: • Before hydrates are formed, the phases are emulsified from the flow turbulence, possibly creating gas bubbles entrained

in the oil and water, oil emulsified in water, and water emulsified in oil. The emulsified/entrained droplets/bubbles create the surface area for hydrate formation.

• When the temperature and pressure conditions are within the hydrate stability region, hydrate will most likely form at the interface between the water and hydrocarbon fluid (oil or gas), forming a hydrate shell around the water/oil droplets emulsified in oil/water.

• Another possible location for hydrates to initially form is on the pipe walls, in the form of deposits, as these will be wet and constantly exposed to the gas.

• Hydrate growth will be limited by either availability of water and gas or temperature. The initial hydrate shell (~30-50 am thick6) is probably formed very quickly, as the kinetics of hydrates is known to be quite fast, given that the right components (water and gas) are present for formation. Soon after, the process for continued hydrate growth is typically mass transfer or heat transfer limited. In the former, water and/or gas must diffuse to the interface, and in the latter, heat must be removed as the hydrate formation is an exothermic (heat released) process.7

• Once a sufficient amount of hydrates are in the system, the hydrate slurry will change the rheology (flow behavior) of the system,8 with hydrate either suspended in the fluid phase or deposited on the solid surface.

• Once hydrates are present, the hydrate particles may interact to agglomerate into larger aggregates or continually grow on the existing deposits on the pipe wall. The interaction of hydrate particles will largely depend on the continuous fluid phase. If the hydrate particles are dispersed in a water-continuous phase, the binding forcing between the hydrate particles is minimal, and they will remain dispersed. If the particles are dispersed in an oil-continuous phase, it is likely that the particles will bind to form large aggregates due to the water capillary bridging formed between the particles.9

• Hydrate deposition on the wall is an important phenomena which may be responsible for eventual hydrate blockages under steady-state operation, as these deposits can slowly build-up over time. Hydrate deposits on the wall can narrow the flow channel, similarly to wax/asphaltene deposition.

• The last stage in this conceptual model is the jamming of hydrate particles, causing the blockage of the system. If we can understand how jamming occurs, then perhaps we can develop strategies to prevent the system from jamming.

Figure 2. Conceptual model for hydrate formation, agglomeration, and plugging in a multiphase flow system consisting of gas, oil, water, and hydrates (adapted from Turner,5 who originally developed this picture with the input from J. Abrahamson, University of Canterbury, Christchurch, NZ).

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The conceptual model described in Figure 2 can be said to be applicable to oil- and water-dominated systems. When considering gas-dominated systems, the main hydrate formation mechanism is deposition on the pipe wall, as shown in Figure 3. These deposits can gradually grow, over prolonged periods of time, to narrow the flow channel and cause significant pressure drops in the system. These deposits, can also detach from the wall (sloughing) due to the fluid shear and the loose chunks of hydrates may eventually accumulated in a flow restriction (e.g., another hydrate deposit, valve, bend) and cause the system to jam.

Figure 3. Conceptual model for hydrate formation and plugging in a gas-dominated multiphase flow system. The conceptual models presented and the phenomena involved in the mechanisms for hydrate formation to plugging form the basis for much of the research that needs to be performed in order to develop a comprehensive model that will fully describe the dynamics and interactions of hydrate in multiphase flow. It is these conceptual models that have guided the research in the Center for Hydrate Research for over a decade and led to the development of CSMHyK (CSM Hydrate Kinetics model) and CSMHyFAST (CSM Hydrate Flow Assurance Simulation Tool), which not only combines the concepts in Figure 2, but is an actual model that is packaged to quantitatively predict the formation and plugging of hydrates in multiphase flow. CSMHyK and CSMHyFAST are currently the only tools available to assist in the hydrate management strategy to determine when, where, and how much hydrates are present in multiphase oil and gas flowlines. CSMHyK is available as a module to OLGA®, the multiphase flow simulator by the SPT Group (a Schlumberger subsidiary), and it can currently model the oil-dominated, water-dominated, and gas-dominated systems. CSMHyFAST is not currently distributed beyond the paying member companies of the CSM Hydrate Consortium; the models available in CSMHyFAST include the oil-dominated and water-dominated systems. These tools are constantly evolving as we continue to do research in this area and improve our understanding and models. CSMHyK and CSMHyFAST are fairly complex tools to use and they do require a significant amount of basic understanding on the different physical models to be applied correctly and to obtain meaningful results. Figure 4 illustrates the application of CSMHyK-OLGA® in the risk assessment for hydrates in a field tieback from the wellhead to the platform.10 The figure shows representative data from the simulations indicating the fraction of the phases along the flowline, pressure drop along different sections of the flowline, and the relative viscosity, which is a measure of the plugging tendency of the system (the reader is directed to another publication for an extensive discussion of the results shown in these plots10). In its present version, CSMHyK is capable of considering hydrate formation in oil-dominated system (water emulsified in an oil continuous phase). Our current efforts in studying hydrate formation in high water cut systems will extend CSMHyK to consider hydrate formation in cases where a free water phase is present. Our goal is to add the capability in CSMHyK to consider hydrate formation in gas-dominated systems, which would then include the most important type of systems encountered in flowlines.11 CSMHyK has been developed based on experimental data and observations in the laboratory and flowloops. It is recognized that CSMHyK has not been “validated” with actual field data, as hydrate blockage in flowlines are not purposely formed, with the exception of two cases, the Tommeliten-Gamma field test and the Werner-Bolley field test.12 As such, to the best of our knowledge, the utilization of CSMHyK in industry has been limited to after-the-fact cases (CSMHyK was used to understand how, when, and where hydrates formed after a hydrate plug had already formed and removed) or in preliminary assessment of trouble spots in flowlines. The true test of CSMHyK will only come with time after several cases have been

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considered, not as a solution to hydrates in flow assurance, but as a tool for assess the risk of hydrates under different field and operating conditions.

Figure 4. CSMHyK-OLGA® allows the simulation of hydrates formation in multiphase flow, giving information into when, where, and how much hydrates are formed in flowlines (middle left). This tool considers steady-state and transient conditions, and provides a means to assess the risk of hydrate in flowlines by measures of the pressure drop (middle right) and relative viscosity of the condensed phase (bottom). Hydrate Remediation Blockages of flowlines with hydrates do happen with a good deal of frequency and it is imperative to remove those blockages as quickly and safely as possible. Any down time with stoppage of production is lost revenue in terms of the producing fluids. It is comforting to know that no flowlines have been abandoned due to hydrate blockages and there are no cases where hydrate blockages have not been removed. Hydrate blockages are typically due to operational/equipment issues, as industry practices are well defined to minimize the risk of hydrates blockage under normal operations. In cases where hydrate blockages are identified as the cause for flow stoppage in flowlines, first the blockage location must be roughly identified, and then a strategy for its removal developed such that all safety precautions are taking to eliminate the possibilities of pressure build up in the flowline. The typical approach for hydrate blockage removal is depressurization, with two-sided depressurization as the preferred method and one-sided depressurization if the only option available (due to the liquid head on one side of the blockage). Depressurization of the system causes the hydrate plug to melt (radially, as opposed to axially). The dissociation of the hydrate plug must be done only sufficiently to allow for pressure communication in the flowlines so that fluids (e.g., thermodynamic inhibitors) can be injected to further dissociate the plug. One tool developed to help in estimating the dissociation of the hydrate plug is CSMPlug. The purpose of this tool is to provide an order of magnitude time for partial dissociation of the hydrate plug so an annular gap between the plug and the flowlines forms to establish pressure communication, as illustrated in Figure 5. The tool can consider two-sided and one-sided depressurization, as well as calculate the potential of the hydrate plug becoming a projectile in the flowlines due to its possible displacement upon depressurization. The displacement of the hydrate plug is an important consideration as the flowline can experience significant pressure fluctuations during the movement of the plug. CSMPlug is based on one-dimensional radial heat transfer model with conduction and convection of heat through the pipe wall.

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Figure 5. Illustration of hydrate plugs in flowlines and its partial dissociation, creating an annular gap so that pressure communication can be established. Conclusion The field of hydrates in flow assurance has significantly matured over the last couple of decades, in large part from the broader understanding of the phenomena involved in the formation and accumulation of hydrates in multiphase flow. The thermodynamics of hydrate formation is well defined and can be predicted with good certainty using tools like CSMGem. These thermodynamics predictions are essential in the hydrate prevention strategy for determining the displacement of the hydrate equilibrium boundaries in the presence of thermodynamic inhibitors. In the hydrate management strategy, understanding of the mechanisms for hydrate formation under transient multiphase flow is essential. Tools like CSMHyK and CSMHyFAST have been developed to capture the formation, accumulation, and eventual plugging of hydrates in oil-dominated, water-dominated, and gas-dominated systems. The physical models in these tools are constantly evolving as we further our knowledge and understanding of hydrates in multiphase flow. Hydrate are occasionally inevitable, and a tool like CSMPlug is essential for estimating the time for partial dissociation of the hydrate plug and evaluating the safety risk associated with the dislodging of these plugs in flowlines. Acknowledgements The concepts and ideas presented have been developed over a number of years at the Center for Hydrate Research at the Colorado School of Mines, resulting from the research of current and past graduate students, postdoctoral researchers, visiting scholars, and faculty. The Center has been financially supported by a number of sponsoring organizations, including current and past member companies of the CSM Hydrate Consortium (BP, Champion Technologies, Chevron, ConocoPhillips, Eni, ExxonMobil, Halliburton, Multichem, Nalco, Petrobras, Schlumberger, Shell, Statoil, SPT Group, Total), DeepStar, the U.S. National Science Foundation, and the U.S. Department of Energy. References 1. Natural Gas Hydrates in Flow Assurance; Sloan, D., Koh, C., Sum, A. K., Eds.; Elsevier: New York, 2010. 2. Carroll, J. Natural Gas Hydrates: A Guide for Engineers; Gulf Publishing: Tulsa, 2002. 3. Creek, J. L., Subramanian, S., Estanga, D. New Methods for Managing Hydrates in Deepwater Tiebacks. Proceedings of the Offshore

Technology Conference, Houston, TX, May 2-5, 2011. 4. Ballard, A. L., Sloan, E. D., “The next generation of hydrate prediction - Part III. Gibbs energy minimization formalism,” Fluid Phase

Equilibria, 2004, 218 (1), 15-31. 5. Turner, D. Clathrate Hydrate Formation in Water-in-Oil Dispersions. Ph.D. Dissertation, Colorado School of Mines, Golden, CO, 2005. 6. Taylor, C. J., Miller, K. T., Koh, C. A., Sloan, E. D., “Macroscopic investigation of hydrate film growth at the hydrocarbon/water

interface,” Chemical Engineering Science 2007, 62, 6524. 7. Sloan, E. D., Koh, C. A. Clathrate Hydrates of Natural Gases; 3rd Ed., CRC Press: Boca Raton, 2008. 8. Camargo, R., Palermo, T. Rheological Properties of Hydrate Suspensions in an Asphaltenic Crude Oil. Proceedings of the 4th Int. Conf.

on Gas Hydrates, Yokohama, Japan, May 19-23, 2002. 9. Aman, Z. M., Joshi, S. E., Sloan, E. D., Sum, A. K., Koh, C. A., “Micromechanical cohesion force measurements to determine

cyclopentane hydrate interfacial properties,” Journal of Colloids and Interface Science 2012, 376, 283-288. 10. Zerpa, L. E., Sloan, E. D., Sum, A. K., Koh, C. A. Generation of Best Practices in Flow Assurance Using a Transient Hydrate Kinetics

Model. Proceedings of the Offshore Technology Conference, Houston, TX, May 2-5, 2011. 11. Zerpa, L. E., Aman, Z. S., Joshi, S., Rao, I., Sloan, E. D., Koh, C. A., Sum, A. K. Predicting Hydrate Blockages in Oil, Gas and Water-

Dominated Systems. Proceedings of the Offshore Technology Conference, Houston, TX, April 30-May 3, 2012. 12. Hatton, G. J., Kruka, V. R. Hydrate Blockage Formation—Analysis of Werner Bolley Field Test Data. DeepStar CTR 5209-1.