Article pubs.acs.org/EF
Formation of Hydrate Slurries in a Once-Through Operation Jason W. Lachance,*,† Larry D. Talley,† Don P. Shatto,‡ Douglas J. Turner,‡ and Michael W. Eaton† †
ExxonMobil Upstream Research Company, Houston, Texas 77098, United States ExxonMobil Development Company, Houston, Texas 77060, United States
‡
ABSTRACT: The major parameters for a hydrate slurry flow model are suggested. A field trial in a once-through pipeline indicated a significantly confined operating region without plugging. The implication of these results is that current versions of hydrate cold flow will need to address hydrate film growth and deposition on pipewalls. Flow loop tests alone do not simulate the extent of plugging because of film growth or deposition. A unique learning in this work is that emulsified droplet distributions were measured as a function of watercut, surfactant concentration, and fluid velocity. Droplet size and droplet size distribution increased with an increasing watercut below the inversion point. Droplet size and droplet size distribution decreased with an increasing surfactant concentration. An increasing surfactant concentration limited wall deposits to some extent. An increasing fluid velocity reduced wall deposits and hydrate slurry viscosity. Wall deposits decreased with a decreasing gas void fraction.
1. INTRODUCTION The formation of gas hydrates in production systems causes several problems, including increased pressure drop because of solids formation, deposition on pipe walls, the increase of fluid viscosity through gas uptake, and of course, the risk of complete blockage of flowlines, umbilicals, and other production tubing.1 These different mechanisms are broadly understood in the flow assurance community; however, the prediction and verification of hydrate slurry behavior in various operating systems is still not available to the community. The broader community is not yet able to operate with confidence within the hydrate region. ExxonMobil recently completed a field trial in a oncethrough, 4 in. diameter, 3.2 km pipeline facility to determine the effect of operating under various hydrate conditions/ scenarios. The objective was to gain experience and confidence to operate in the hydrate region in actual applications. There are large benefits in being able to “cold flow” hydrate-forming systems,2,3 including reducing or eliminating insulation, eliminating chemicals, and extending flowline distances. The target areas tested in the field trial system were (1) comparing hydrate slurry performance in a once-through flow system versus a 4 in. flow loop at various operating conditions and scenarios, (2) determining the effect of long-term operations while mimicking actual field life conditions during hydrate slurry formation, and (3) characterizing transient performance during rate changes and shut-in/startup with hydrate slurry formation. On the basis of the results of these tests, unique hydrate slurry flow models were developed or verified. These will enable oil and gas development engineers to predict during design phases (a) potential problem areas related to hydrates, (b) the effect of hydrate slurries on steady-state system fluid dynamics, and (c) the ability of fields to restart during unplanned shutdowns.
Table 1. Compositions of Field Trial Fluids gas
water
composition
mole fraction
composition
mole fraction
H2 He N2 CO2 H2S C1 C2 C3 iC4 nC4 iC5 nC5 C6 C7+ sum
trace 0.0005 0.0141 0.0067 0 0.9633 0.0127 0.0021 0.0001 0.0002 trace 0.0001 0.0001 0.0001 1
H2 He N2 CO2 H2S C1 C2 C3 iC4 nC4 iC5 nC5 C6 C7+ sum
0 0 trace trace 0 0.0003 0.0028 0.0227 0.0097 0.0293 0.0194 0.0241 0.0474 0.8443 1
ion
mg/L
cations Na 19770 Ca 555 K 1290 Mg 251 Fe 5.4 anions Cl 35989 HCO3 277.3 SO4 2310 CO3 nil OH nil
2.1. Field Trial Fluid Composition and Properties. The field trial gas composition, crude oil composition, and water analysis are shown in Table 1. The gas was sweet with no H2S and very little CO2. The fluid compositions yielded the hydrate curve shown in Figure 1, calculated using an ExxonMobil proprietary program. The stream was saturated with respect to water in the program. As seen in the plot, operating at 1200 psia put the hydrate formation conditions between 9 and 10 °C. The following key physical properties of the oil, shown in Table 2, impacted droplet size distributions, wax properties, and multiphase flow characteristics. It is important to note that this oil was waxy and had wax deposition tendencies at the operating conditions used in the field trial. Special Issue: Upstream Engineering and Flow Assurance (UEFA)
2. FIELD TRIAL EXPERIMENTAL DETAILS
Received: February 7, 2012 Revised: May 1, 2012 Published: July 11, 2012
The following sections will provide details on the fluids, design, and operation of the field trial. © 2012 American Chemical Society
oil
4059
dx.doi.org/10.1021/ef3002197 | Energy Fuels 2012, 26, 4059−4066
Energy & Fuels
Article
Figure 1. Hydrate formation curve for the field trial fluids. shown to promote hydrate slurry formation.4 Turner and Talley have shown that hydrate slurry performance is optimized as the droplet size decreases.3 Span 80 obtained from Sigma-Aldrich was used to scope this effect and to mimic more stable emulsifying crude oils found in many company portfolios. 2.2. Field Trial Equipment Overview. The field trial had the test capabilities shown in Table 3. A basic process flow diagram of the field trial is shown in Figure 2. Although not obvious from this diagram, the geometry of the field trial piping ranged from horizontal to vertical orientations. This will be discussed more in the Results and Discussion. The various pieces of field trial equipment shown in Figure 2 were located inside the processing plant. Water, gas, and oil entered the test system and were controlled via flow meters (FV-X100, FV-X101, and FV-X105, respectively) to achieve the desired gas/oil ratio (GOR), watercut, and liquid loading required for a given test. The oil and water were initially mixed and sent through EX-1, which cooled the oil and water to the hydrate equilibrium temperature (∼10 °C) using cold glycol. After leaving EX-1, the gas was mixed with the cooled fluids. At this point, the process flow could either be arranged to pass through a static mixer or bypass the mixer by adjusting a series of ball valves. There was also an option at this point to initiate a seeding loop, where most of the flow bypassed the subsequent heat exchangers and then were seeded by a small stream that entered either EX-3 or EX-4 and then recombined after the exchangers. The gas, oil, and water mixture that was cooled by EX-1 and configured to flow through or bypass a static mixer was then sent to either EX-3 or EX-4, which cooled the mixture further into the hydrate region (3−6 °C) to initiate the hydrate formation process. The two parallel exchangers (EX3/EX4) were periodically swapped during a test to perform wax/hydrate remediation on them. Remediation of a heat exchanger required bypassing the 3.2 km pipeline (“test section”), resulting in differential pressure flatlines on the order of 1 h or less during this transition. After leaving EX-3/EX-4, the process path again allowed for a configuration of the fluid flow to pass through a static mixer or bypass the mixer. The hydrate slurry then passed through a Canty particle video microscope (PVM) through above-ground piping and then entered the buried test section. The test section consisted of a 4 in., 1.6 km flowline to a wellsite and a 4 in., 1.6 km flowline returning to the line heater (HX-2).
Table 2. Key Fluid Properties of the Field Trial Crude Oil property
value
wax appearance temperature wax dissociation temperature inversion point API gravity IFT (no Span 80, 10 °C) IFT (with Span 80, 10 °C) emulsion stability (no Span 80) emulsion stability (with Span 80)
37 °C 54 °C ∼90 vol % watercut 43.8° 19.9 mN/m 17.3 mN/m ∼3 min (20 vol % watercut, room temperature, and 300 rpm) ∼20 min (20 vol % watercut, room temperature, and 300 rpm)
In addition to the production fluids, the field trial facility was configured for injection of emulsifiers to modify the oil properties and enhance hydrate slurry performance. Span 80 is a common chemical that is used to promote the formation of water-in-oil emulsions [hydrophilic−lipophilic balance (HLB) of 4.3 ± 1] and has been
Table 3. Field Trial Capabilities and Operating Boundaries range
units
comments
pressures
property
0−1500
psia
fluid temperatures
2−30
°C
limited to 1200 psia because of the water injection system dependent upon flow rates (maximum flow of ∼5 °C low limit) and inlet fluid temperatures; wax deposition limits time at lower temperature and requires heat-exchanger turnover
flow rates gas oil water
0−4300 0−42 0−22
m3/h m3/h m3/h
methanol chemical
0−5 0−2
m3/h m3/h
limited by time and water storage capacity versus pump capacities at higher water flow rates small volume increments 4060
dx.doi.org/10.1021/ef3002197 | Energy Fuels 2012, 26, 4059−4066
Energy & Fuels
Article
Figure 2. Simplified process flow diagram of the field trial system. The hydrate slurry being transported through the test section could be configured to pass through another static mixer or bypass the mixer above ground at the wellsite. The slurry was then transported back to the processing plant and flowed through the line heater (HX-2) to melt any residual hydrates and warm the fluids before entering the separator. Fluids leaving the line heater traveled through PV-X121, which controlled and maintained the entire system pressure by automatically making adjustments based on the pressure measurements leaving EX-3/EX-4. The gas/oil/water were separated and conditioned per normal plant operations directed by site personnel. The field trial also had erosion/corrosion monitors in three locations to monitor the effect of the hydrate slurry compared to the fluid flow conditions without hydrates. Chemical injection (Span 80) was available after EX-1, and methanol injection was available at the inlet and outlet of the buried pipeline test section. 2.3. Field Trial Experimental Matrix. Table 4 provides an overview of the types of tests that were performed at the field trial. This table is not inclusive of all of the tests that were performed; however, it does clearly show the ranges and types of tests that were scoped in this study. In the following sections, data will be presented on several of these tests. The water retrieval tests outlined in this matrix were used to determine hydrate deposition rates and the disposition of any remaining water in the field trial system. During these tests, the water flow was stopped, fluids were transported to a test separator using gas and oil flow, and the water content was measured as fluids were slowly warmed above the hydrate dissociation temperature.
dissociation phases for short durations of time, usually depleting water- or gas-phase components within a few hours. These short-duration “snap shots” correspond somewhat to the state of fluids in a once-through pipeline before a steady-state condition is achieved in the pipeline. When the steady-state condition is achieved in the flow loop, it is not the same as the steady state in a once-through pipeline. This makes studying mechanisms such as wall deposition difficult to interpret in a flow loop, especially a large flow loop. A typical hydrate formation flow loop test is shown in Figure 3. This test was performed on ExxonMobil’s 4 in., 312 ft flow loop in Houston, TX. The plot shows the temperature decreasing up to 6 h into the test, and then a plateauing of the temperature indicates hydrate nucleation and growth for a 2−3 h period. During this time, the pressure drop rose slightly and then plateaued, corresponding to the formation of a hydrate slurry. A once-through test with actual pipeline flowing conditions gives insight into hydrate nucleation, growth, transport, and dissociation at various points within the flowline. The long duration of hydrate nucleation and growth allowed us to see the cumulative effects of hydrate slurry transport. Figure 4 shows pressure drop data from a once-through hydrate formation test in the field trial with similar conditions as the flow loop test in Figure 3. Unlike the flow loop test, the once-through operation gave different results, even though the same fluids and similar run conditions were used in both cases. As seen in many of the field trial tests, an exponential rise in the pressure drop was observed in various sections of the field trial system. Through various techniques, such as heating to just above the hydrate temperature or injecting methanol, these pressure drops were found to be due to hydrates and not other solids, such as wax. It was found during the course of the field trial tests that wall deposits of hydrates were responsible for the majority of the
3. RESULTS AND DISCUSSION The following sections will highlight some of the major findings of the field trial regarding transportation of hydrate slurries. 3.1. Once-Through Hydrate Formation Tests. The first goal of this field trial was to compare the short-duration flow of hydrates in a flow loop versus the long-duration, once-through flow in a pipeline. A flow loop test simulates the time evolution of an initial portion of fluid flowing through a once-through system as it goes through the hydrate nucleation, growth, and 4061
dx.doi.org/10.1021/ef3002197 | Energy Fuels 2012, 26, 4059−4066
Energy & Fuels
Article
Table 4. Overview of Types of Hydrate Tests Performed at the Field Trial test type baseline tests without hydrate baseline test with hydrate turndown (low watercut) turndown without wax inhibitors watercut threshold shut-in/restart turndown (medium watercut) bedding/water retrieval water surge liquid/gas surge water retrieval with warm oil increase gas void fraction (GVF) partial conversion of water to hydrate high watercut blowdown/ repressurization strategies fast methanol transition gradual methanol transition emulsifier test, Span 80
velocity (m/s)
watercut (vol %)
liquid loading (vol %)
1.0−2.5
0−95
50−90
1.0−2.5
0−95
1.0−2.5
2−15
70
1.0−2.5
2−15
70
1.0−2.5
15−60
70
1.0−2.5 1.0−2.5
15−40 15−60
70 70
1.0−2.5
25
70
1.0−2.5
25
70
1.0−2.5
25
40−70
1.0−2.5
25
70
high watercut strategies AA, pigging strategies
1.0−2.5
60−95
90
1.0−2.5
25
70
THI transitions
1.0−2.5
25
70
THI transitions
1.0−2.5
25
70
coalescence/droplet size effects
1.0−2.5
5−20
60−90
comments measure P and T profiles without hydrates determine normal plugging tendencies operating window for velocity effect of wax on hydrate slurries operating window for watercut transient operation operating window as watercut increases signs of bedding/film growth surge at maximum water rate surge at maximum oil and gas rates signs of bedding/film growth operating window for GVF operation with wet hydrates
Figure 4. Hydrate once-through test showing pressure drops in the pipeline and directly after the cool down into the hydrate region. The test ran at 70 vol % liquid loading, 10 vol % watercut, and 1.22 m/s.
Figure 5. Comparison of operating envelopes for flow loop versus once-through pipeline using field trial fluids. Each curve represents a boundary between the fluid parameters that give low-viscosity hydrate slurries (outside the curves) versus high-viscosity slurries that lead to plugging (inside the curves). Boundaries are shown for two fluid velocities (1.5 and 2.5 m/s) for both the large flow loop and the field trial.
variety of different methods, including X-ray analysis of the above-ground piping between EX3/EX4 and the test section, which showed the deposition/film growth on the pipe walls, especially around bends. Figure 4 shows that it took nearly 2−3
increase in pressure drops and not agglomeration, jamming, bedding, or slurry viscosification. This was determined using a
Figure 3. Hydrate formation test at 25% watercut, 30% gas void fraction, and 1.75 m/s fluid velocity with field trial fluids in the ExxonMobil flow loop (dissociation not shown). 4062
dx.doi.org/10.1021/ef3002197 | Energy Fuels 2012, 26, 4059−4066
Energy & Fuels
Article
velocity. As anticipated, the watercut had a significant impact on water droplet size and interfacial contact, as shown in Figure 6. The photos show that an increasing watercut increased the droplet size distribution. The photos also show that the ability of water droplets to contact each other increased rapidly with watercut. Therefore, the hydrate transportability was expected to be worse at higher watercut, which is verified in Figure 7. Figure 7 shows that the higher watercut at 20 vol % resulted in a 500 kPa pressure drop after 7 h compared to 15 h in the 5 vol % watercut case. In both cases, no aggregates were observed in the PVM and the increase in pressure drop was not uniform throughout the whole system. From this, it was concluded that the increase in the pressure drop was due to deposition/film growth on the pipe wall and not aggregation. It is also important to note that the bedding velocities for these conditions were around 0.5 m/s, which is well below the 1.75 m/s fluid velocity in these tests. This fact led to the hypothesis that the observed increase in the pressure drop was due to the buildup of hydrates on the pipe wall. With the higher volume of water droplets contacting the steel surface, buildup was much faster. However, the volume of water droplets is not the only factor affecting the deposition rates. Dispersion stability was also a factor affecting deposition rates. Span 80 (Sigma-Aldrich) was added to our system to increase the emulsion stability, as indicated in Table 4. This had a dramatic effect on the droplet size distributions, as shown in Figure 8. The addition of Span 80 significantly reduced the droplet size distribution. Also, the increased emulsion stability aided in further limiting the deposition on the wall, as shown in the significantly longer duration test run in Figure 9. The test in that figure ran for 83 h before reaching similar pressure drops as the tests without Span 80 reached in 10−12 h. The increased emulsion stability maintained the dispersion longer, which aided in reducing the aggregation tendencies and also hindered water smearing, water wetting of the pipe wall, and water wetting of any existing hydrate film. 3.3. Effect of Liquid Loading, Flow Regimes/Velocity, and Geometry on Hydrate Transport. As shown earlier, Figure 5 shows the effect of liquid loading and velocity on the operating regime for hydrate transportability. As liquid loading increased and velocity increased, the hydrate transport operating window opened. In general, the liquid loading and velocity did not have as much of an effect on the deposition rates as the water dispersion characteristics; however, these factors played a large role in aggregation and overall hydrate transportability. These two variables were ultimately responsible for the flow regime characteristics of the fluid. In the field trial, transitions from slug flow to stratified flow to complete dispersed flow were observed. It was found that the higher shear flow regimes tended to delay the appearance of hydrate deposits on the wall, as shown in the slug flow test in Figure 10. Several slug flow tests were performed at varying slug frequencies, with the most rapid slug frequency tests delaying deposition the most. As seen in several of the previous plots, the above-ground piping between EX3/EX4 and the buried, 3.2 km test section, referred to as “section G” in the figures, always tended to increase in the pressure drop more rapidly than other locations. This section had several vertical sections and also several 90° bends. On the basis of X-ray tests and comparisons to the horizontal sections, the vertical sections tended to have more
Figure 6. Effect of watercut on dispersion characteristics. The photographs were taken by the Canty PVM. Watercut (WC) is the volume percentage of total liquid flow.
h to see significant increases in the pressure drop in the oncethrough operation. The field trial tests confirmed that flow loops do not do well at replicating the various mechanisms of hydrate failure mechanisms, particularly deposition. However, the flow loops did provide consistent results on bulk fluid slurry behaviors, such as agglomeration. Figure 5 shows the operating conditions for transporting hydrate slurries in this fluid in regards to the bulk fluid properties. Of course, to understand actual operations, one would also need to consider the rates of deposition and film growth to predict the overall impact of hydrates on the pipeline pressure drop. As seen in Figure 5, the operational envelope for the field trial is smaller than for the large flow loop because of the longterm cumulative effects of deposition and film growth in a once-through system. Deposition and film growth lead to sloughing of deposits, which promotes jamming of hydrate aggregates and ultimately causes increases in the pressure drop with or without complete plugging. Interestingly, there is a maximum in the plugging trends at intermediate watercuts. Then, the operating window opens back up at higher watercuts (above about 80% in this figure) after the inversion point is reached. This was observed for the large flow loop and is assumed to be the case for the once-through field trial system. The following sections will show results on how various changes in operating conditions affect the deposition/film growth rates and transportability of hydrate slurries. 3.2. Effect of Water Dispersion Characteristics on Hydrate Transport. Of all of the various flowing conditions, the water dispersion characteristics of the flowing fluids showed the most effect on hydrate transportability and depositional rates. Even though this study only shows one fluid type, several fluid types/conditions have been tested. Water dispersion characteristics were the most important factors in hydrate transportability in this study. In this field trial, the main parameters that were adjusted to change water dispersion properties were the watercut, the concentration of chemical for emulsion stability, and the fluid 4063
dx.doi.org/10.1021/ef3002197 | Energy Fuels 2012, 26, 4059−4066
Energy & Fuels
Article
Figure 7. Comparison of field trial runs at 5 and 20 vol % watercut, 70 vol % liquid loading, and 1.75 m/s without Span 80. Decreases of differential pressure were due to switching heat exchangers. The section of above-ground piping between EX3/EX4 and the buried pipeline is referred to as section G. The first and second legs of the pipeline refer to the first and second 1.6 km legs of buried pipeline in the test section. The two legs were joined above ground at a wellsite not associated with the field trial.
uniform deposition, with the main contributor to increased differential pressure being deposition around the bends, specifically downstream of the bend in the stagnation zones. 3.4. Transient Operations. Oil and gas fields do not typically operate in the hydrate region during steady state; however, many pipelines do enter the hydrate region during transient operations, such as shutdowns or turndowns. Most hydrate plugging events typically occur during transient operations. Therefore, understanding how to recover out of the hydrate region during a transient situation is valuable. The field trial included several transient operation tests, including shutdowns and rate changes. Figure 11 shows a successful restart with fluids entering the pipeline in the hydrate region after a 7 day shut-in. The plot shows the pressure drop stepping up as the flow rate was increased in steps. During the course of this process, no large spikes were observed, indicating that the bulk fluid was flowing and aggregates did not appear to be jamming; however, once the flow rates stabilized, a steady decrease in the pressure drop was observed as the flowline
warmed along the 3.2 km length, indicating that some deposition had occurred earlier, which was melting at this point. Several factors affected the ability to restart while in the hydrated condition, including rates of restart, deposition rates, and liquid holdup. In a commercial operation, there will also be operational issues, such as completion restart schedules and JT cooling at manifold/boarding valves that will need to be considered.
4. MAJOR PARAMETERS AFFECTING HYDRATE SLURRY FLOW The key objective of the field trial was to learn about the major parameters affecting hydrate transport. It will also be important to develop models to predict the ability to flow hydrates in a pipeline. The numerous results from the field and also the laboratory have aided in developing hydrate transport models for use in predicting transient hydraulic behavior of hydrate slurries in field applications. Although not all of the factors are shown in 4064
dx.doi.org/10.1021/ef3002197 | Energy Fuels 2012, 26, 4059−4066
Energy & Fuels
Article
Figure 10. Differential pressures in various sections of the field trial with a fast-frequency slug flow regime. Conditions were 5 vol % watercut, 60 vol % liquid loading, and 2.1 m/s. Section G or the cooling section refers to the above-ground piping between EX3/EX4 and the buried, 3.2 km test section. The first and second legs of the pipeline refer to the first and second 1.6 km legs of buried pipeline in the test section. The two legs were joined above ground at a wellsite not associated with the field trial. Figure 8. Droplet size distributions of water droplets with the addition of Span 80. The large, dark-ringed spheres are gas bubbles. The photographs were taken by the Canty PVM. Watercut (WC) is the volume percentage of total liquid flow.
(8) mass transfer (flow regime and rate of conversion versus shear, especially acid systems), (9) aggregation tendencies (adhesive forces, watercut, and emulsion type/characteristics), (10) oilfield chemical interactions (effect on aggregation/ deposition), (11) rate of restart, limited by completion restart schedules and operations, and (12) wax/asphaltene characteristics and interactions.
5. CONCLUSION The ability to flow hydrates during steady-state and transient operations with confidence that plugging will not occur is extremely beneficial in the oil and gas industry. This ability will help in developing new resources, especially in harsher conditions (lower temperatures and higher pressures). It will also be useful when planning strategies for recovering from unplanned events. This paper is not comprehensive and only details one fluid type. However, it does provide some of the key factors that should be considered in all hydrate slurry predictions. The once-through field trial showed the complexity of predicting the hydraulics of flowing hydrates.
Figure 9. Field trial 83 h test with Span 80 at 5 vol % watercut, 70 vol % liquid loading, and 2.0 m/s (periodic differential pressure drops were due to heat-exchanger transitions). The section of above-ground piping between EX3/EX4 and the buried pipeline is referred to as section G. The first and second legs of the pipeline refer to the first and second 1.6 km legs of buried pipeline in the test section. The two legs were joined above ground at a wellsite not associated with the field trial.
■
AUTHOR INFORMATION
Corresponding Author
*Telephone: +1-713-431-6298. E-mail: jason.w.lachance@ exxonmobil.com. Notes
The authors declare no competing financial interest.
■
this paper, the following factors need to be included in any prediction tools used for determining the ability to flow hydrates with confidence: (1) total hydrate conversion potentials (salt, gas composition, gas/water amounts, and length of conversion zone), (2) deposition rates (bedding and film growth on wall), (3) flowline geometry (jamming potentials, low shear zones, and hold-up), (4) dissociation rates and locations, (5) liquid loading (particle transport potential) for gas or liquid systems, (6) three-phase fluid velocity (shear) for aggregation, jamming, and sloughing potentials, (7) heat transfer (rate of conversion versus shear),
REFERENCES
(1) Sloan, E. D.; Koh, C. A. Hydrates in production, processing and transportation. Clathrate Hydrates of Natural Gases, 3rd ed.; CRC Press (Taylor and Francis Group): Boca Raton, FL, 2008; Chapter 8, pp 643−684. (2) Lund, A.; Lysne, D.; Larson, R.; Hjarbo, K. W. Method and system for transporting a flow of fluid hydrocarbons containing water. U.S. Patent 6,744,276, May 4, 2000. (3) Turner, D.; Talley, L. Hydrate inhibition via cold flowNo chemicals or insulation. Proceedings of the 6th International Conference
4065
dx.doi.org/10.1021/ef3002197 | Energy Fuels 2012, 26, 4059−4066
Energy & Fuels
Article
Figure 11. Test was shut in with fluids above the hydrate equilibrium temperature. Air and ground temperatures cooled the fluids below the hydrate equilibrium temperature. After a 7 day shut-in period, flow was restarted with fluids initially entering the pipeline below the hydrate equilibrium temperature. The fluid temperature was slowly ramped up above the hydrate equilibrium temperature to simulate a subsea flow line restart. Flow velocities and pressure drops were measured over the 3.2 km test section. Temperatures were measured at the inlet and outlet of the test section. on Gas Hydrates (ICGH 2008); Vancouver, British Columbia, Canada, July 6−10, 2008; Paper 5818. (4) Huo, Z.; Freer, E.; Lamar, M.; Sannigrahi, B.; Knauss, D. M.; Sloan, E. D., Jr. Chem. Eng. Sci. 2001, 56, 4979−4991.
4066
dx.doi.org/10.1021/ef3002197 | Energy Fuels 2012, 26, 4059−4066
