ARTICLE pubs.acs.org/EF
Hydrate Plug Dissociation via Nitrogen Purge: Experiments and Modeling Justin L. Panter,† Adam L. Ballard,‡ Amadeu K. Sum,† E. Dendy Sloan,† and Carolyn A. Koh*,† †
Center for Hydrate Research, Department of Chemical Engineering, Colorado School of Mines, Golden, Colorado 80401, United States ‡ BP America, Houston, Texas 77079, United States ABSTRACT: We present a novel and promising method for the remediation of gas hydrate blockages in oil and gas pipelines, involving purging the gas hydrate plug with nitrogen gas. The resulting lower chemical potential of the hydrate former in the gas phase promotes hydrate dissociation, even though the pressure and temperature remain unchanged. Laboratory measurements on hydrate dissociation enabled the development of a model that estimates the dissociation time for gas hydrate plugs using nitrogen. The hydrate plug dissociation mechanism using a nitrogen purge was shown to involve growing channels and was significantly different from the radial dissociation mechanism observed for the conventional plug depressurization method. The nitrogen purge plug dissociation method provides an important new technology for hydrate plug remediation, in which the hydrate is permeable to gas.
’ INTRODUCTION Gas hydrate blockages in transmission pipelines are a major flow assurance and safety concern for the oil and gas industry. Gas hydrates (or hydrates) are crystalline solids composed of water (host) molecules combined with guest molecules (e.g., methane, ethane, propane, etc.) to form a hydrogen-bonded network enclathrating the guest molecules, usually at high pressures and low temperatures.1 As the oil and gas industry moves exploration and production into deeper water depths, the consequences of forming hydrate plugs in subsea pipelines become increasingly more severe. As a consequence, the mitigation of hydrates in flow assurance is experiencing a paradigm shift, moving from hydrate avoidance, where thermodynamic inhibitors are used to shift the temperature and pressure stability conditions, toward risk management, where kinetic inhibitors and anti-agglomerants are used to delay hydrate formation or prevent hydrate particle agglomeration, respectively.2 In the strategy of risk management using antiagglomerants and/or stabilized cold flow, one prevents small hydrate particles from agglomerating to form a hydrate plug, such that the resulting hydrate slurry can be transported in a dispersed form through the pipeline.1,3 The current methods for hydrate plug remediation involve one- or two-sided depressurization, direct electrical heating, and inhibitor injection. Even though these methods are widely used in the industry, each has limitations and poses serious safety concerns. Removal of a hydrate plug by depressurization, either oneor two-sided, can be jeapardized by high-pressure gas pockets trapped between multiple plugs, which can result in dangerous conditions because of the pressure differential across the plugs (plugs can dislodge and become a projectile in the pipeline).46 In deep-water scenarios, depressurization alone is often insufficient to destabilize a hydrate plug because of the residual liquid head. With electrical heating, one of the major concerns is the overpressurization that may be generated from localized heating r 2011 American Chemical Society
of the plug. Finally, hydrate plugs are typically impermeable to liquids, and as such, in most cases, inhibitor injection (e.g., methanol) becomes impractical or too slow to be viable. The use of air and nitrogen (N2) to dissociate hydrates in sediment has been studied by Haneda et al.7 and Masuda et al.8 Masuda et al.8 passed nitrogen through limestone cores filled with hydrates and showed that, as the nitrogen passed through the core, hydrates dissociated. The fundamental concept behind this dissociation method is a chemical potential difference for methane in the hydrate and gas phases. Haneda et al. studied the dissociation behavior of methane hydrate by passing air through synthetic hydrate-bearing sediment.7 Figure 1 shows a Px phase diagram for nitrogen þ methane and nitrogen þ methane þ ethane mixed hydrates and also a PT diagram for binary hydrates containing nitrogen þ methane compared to pure methane hydrate. The phase boundaries in the figure illustrate how increasing amounts of nitrogen in the gas phase shifts the hydrate stability conditions to higher pressures and lower temperatures. On the basis of this concept, nitrogen can be viewed as a “thermodynamic inhibitor” and used to help dissociate hydrate plugs that would otherwise be stable. Here, we present the experimental and modeling study performed for this novel and promising method for the remediation of gas hydrate blockages in oil and gas pipelines by measuring the dissociation of hydrate plugs by nitrogen purge from different hydrate formers and pressure conditions.
’ EXPERIMENTAL SECTION Hydrate Formation and Experimental Apparatuses. Hydrate plugs in gas/oil pipelines are usually formed under shear conditions and can quickly form in a matter of minutes to hours.10 To form Received: February 4, 2011 Revised: April 18, 2011 Published: April 19, 2011 2572
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Figure 1. (Left) Equilibrium pressure versus nitrogen mole fraction in the water-free gas phase calculated at 40 °F (remaining gas phase is either pure methane or a mixture of 75 mol % methane and 25 mol % ethane). (Right) Calculated phase diagram for gas hydrates formed with mixtures of nitrogen and methane. Both with equilibrium boundaries generated with the CSM Gibbs energy minimization (CSMGem) program.1,9
Figure 2. Schematic of the stainless steel cell showing the main components of the system. hydrates on a laboratory time scale in a static system, an experimental procedure was adopted that was first proposed by Stern et al. and rigorously tested by Peters for forming reproducible hydrate samples.11,12 Hydrate plugs were synthesized in one of two different stainless-steel cylindrical cells (cf. experimental cell used by Peters12). The main section of the first apparatus (long cell) was a 36 in. long stainless-steel cell, with an internal diameter of 1 in. and an internal volume of 28.3 in.3 The second (short) cell was 8 in. long and had an internal diameter of 2 in. The internal volume of this cell was 25.1 in.3 Each cell (long or short) was kept in a temperature-controlled bath filled with a propylene glycol/ water mixture. Figure 2 shows a schematic of the experimental apparatus. Previous studies provided the heuristics for the current hydrate formation procedure, which is briefly summarized here.5,1115 After the cell was loaded with small ice particles of approximately 250500 μm (200 g in the long cell and 160 g in the short cell), sieved through a 500 and 250 μm mesh, the cell was pressurized to about 2000 psig with the desired gas mixture. Because the gas entering the cell was at room temperature, the gas had to be added slowly through a cooling section (maintained at 25 °F), to ensure that the temperature of the cell was below the ice point. Structure I (sI) hydrate plugs were formed from pure methane (Matheson Trigas, 99.99% purity). Structure II (sII) hydrates were formed from a methaneethane mixture (74.79 mol % methane and 25.21 mol % ethane; Matheson Trigas, 99.9% purity).16 Hydrates were also formed in a visual apparatus shown in Figure 3, which illustrates the Jerguson sight glass cell, which allowed for direct visual observation of the hydrate dissociation process. The internal cross-section of this cell
was 0.6 1 in. The field of view was 13.5 in. long 1 in. wide. The internal volume of the Jerguson cell was 13.2 in.3 Hydrates were formed in the visual Jerguson cell from a solution of 100 ppm sodium dodecyl sulfate (SDS) and deionized water. It is well-known that adding a surfactant to a watergas mixture greatly decreases the induction time and increases conversion.1719 With this solution, >95% of the water in the system was converted to hydrate. The volume of the gas reservoir (pore volume and line volume) was not large enough to be considered infinite; however, powder X-ray diffraction and Raman spectroscopy were performed on the hydrate samples (recovered after quenching in liquid N2 and depressurization) and confirmed that uniform samples of sII hydrate were formed from the methaneþethane gas mixture.20 Hydrate Dissociation. In the stainless steel cells (long and short), all dissociation experiments were performed at 40 °F (this temperature corresponds to that at the ocean floor) and over a pressure range of 7002000 psig nitrogen gas purge. Once the conversion of ice to hydrates had stopped (reaching >95% conversion based on pressure drop, typically after 35 days), the pressure in the system was adjusted to the experimental pressure. The nitrogen used was ultra-high-purity (>99.99%) supplied by General Air. The inlet pressure of nitrogen was set to 100 psi over the experimental conditions (upstream of the mass flow controller) to ensure a pressure gradient across the mass flow controller. The pressure downstream of the flow controller was held constant at experimental conditions. At the beginning of the experiments (zero time), gas chromatography (GC) measurements of the outlet stream were initialized, data acquisition was restarted, nitrogen flow was started at 3 standard liters per 2573
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Figure 3. Schematic of the visual Jerguson cell apparatus for hydrate dissociation.
Figure 4. Images of the hydrate dissociation process at 700 psig, 40 °F, and 3 SLPM of nitrogen after (a) 2 min, (b) 10 min, (c) 20 min, (d) 40 min, and (e) 120 min. Hydrate formed from a gas mixture of 75 mol % methane and 25 mol % ethane. minute (SLPM), the purge valve was opened, and the outlet valve was opened. The back-pressure regulator was fine-tuned during the first few minutes of the experiments because of the rapid changes in the flow rate. During the experiments, no measurable pressure difference was observed between the up- and downstream side of the porous plug. In the sI experiments, the GC method involved sample acquisitions programmed for every 3.5 min, lasting 61 min. In the sII experiments, sampling was performed every 4 min, lasting 70 min. At that time, the GC measurements needed to be stopped and restarted. This was repeated until the outlet concentration of the hydrate-forming gases (methane or methane/ethane) was very small (peaks from GC). Once the experiment was completed, the cell was sealed and heated to 77 °F to dissociate any remaining hydrate in the system. Once the pressure stabilized, the bath temperature was decreased to 40 °F. After reaching 40 °F, the pressure difference between the end of the experiment and the current pressure was recorded. Using this pressure difference, the amount of hydrate remaining in the system at the end of the experiment was determined using an equation of state (i.e., PengRobinson). The equation of state was used to calculate the number of moles of gas in the system before and after the cell was heated. Using this information, the amount of hydrate remaining was calculated. In the Jerguson cell, hydrates were dissociated in a similar manner as that in the stainless steel cell. All hydrates in the Jerguson cell were dissociated at 700 psig and 40 °F. The flow rate of nitrogen was constant at 3 SLPM. A video camera was setup to record the dissociation process.
Figure 5. Hydrate dissociation in the stainless steel cells at two different pressures. Structure I methane hydrate was initially formed for each of the experiments shown. The amount of free gas in the cell was subtracted to obtain the percent dissociation. The dissociation experiment was stopped when hydrates were no longer visible in the cell.
’ RESULTS AND DISCUSSION Hydrate Dissociation Experiments. The Jerguson cell allowed for quick, visual, and qualitative experiments to aid in the understanding of the dissociation process. Because the Jerguson cell was not equipped with a GC or outlet mass flow meter, only qualitative data were obtained from this apparatus. Figure 4 shows the sII hydrate dissociation process over a period of 120 min in the Jerguson cell. As seen in Figure 4, most of the hydrates were dissociated in the first 40 min, after which a substantial amount of free water accumulated, acting as a masstransfer barrier and greatly decreasing the dissociation rate. The formation of channels through the hydrate is clearly shown in Figure 4, as well as a non-axial front moving through the hydrate. These channels were initially small and grew radially as time progressed. Figure 5 shows the dissociation data for sI methane hydrate in the stainless steel cells. It is seen that the initial dissociation 2574
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Figure 6. Hydrate dissociation in the stainless steel cells at two different pressures. Structure II hydrates from a methaneethane mixture was initially formed for each of the experiments shown. The amount of free gas in the cell was subtracted to obtain the percent dissociation.
rate was very high, with around 50% of the hydrate dissociated in the first hour of nitrogen purging. Structure II hydrates were of great interest because nearly all hydrates formed in gas/oil pipelines are sII.21 A comparison of the sII hydrate dissociation data in both the long and short cells is shown in Figure 6. It is hypothesized that there were two possible reasons for the decrease in the dissociation rate after the initial fast dissociation period (as seen in Figures 5 and 6). The first is a decrease in the surface contact area between nitrogen and the hydrate. When nitrogen was first injected into the hydrate, there was a lot of contact area between the hydrate and nitrogen. As the hydrate dissociated, this surface area was decreased (because of channeling), thus reducing the dissociation rate; in this process, as the channels increased in size, more flow would be diverted through the channels (path of least resistance), decreasing the contact area between nitrogen and the hydrate. The decrease in the surface area resulting from the formed channels would effectively decrease the mass-transfer rate of methane from the dissociated hydrate. The second possible reason for the decrease in the dissociation rate is the release of water as the hydrate dissociated. As the hydrate dissociated, methane was released and the water was left behind. As more and more hydrate dissociated, this water began to pool at the bottom of the cell because of gravity (cf. CT X-ray image analysis during hydrate plug dissociation by Gupta22). This water pool greatly increases the mass-transfer resistance between nitrogen in the gas phase and the hydrate. From the visual experiments in the Jerguson cell, it was hypothesized that the hydrate dissociation would take longer in a larger diameter cell then in a smaller diameter cell. This is because the hydrate appeared to dissociate from the inside out (radially) instead of axially. However, the dissociation rates in the four different dissociation experiments for each hydrate structure (shown in Figure 6) were very similar. Also, sII hydrate required more time to dissociate than sI hydrate. One possible explanation for this is the difference in equilibrium conditions between sI hydrate and sII hydrate. At 40 °F and 1000 psi, the equilibrium mole fraction of nitrogen in the gas would be 0.48 for sI hydrate and 0.78 for sII hydrate, as seen in Figure 1.
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Figure 7. Reproducibility of the dissociation of sI hydrate at 700 psig and 3 SLPM of nitrogen flow.
Figure 8. Methane hydrate plug (center) before dissociation, (left) after 1 h of nitrogen purging at 3 SLPM, 40 °F, and 700 psig, and (right) after 1 h of depressurization at ambient conditions.12 Samples were obtained after quenching in liquid nitrogen and quickly opening of the cell. The inner diameter of the cell is 2 in.
To verify the reproducibility of these measurements, the 700 psig experiment was performed again. Figure 7 shows that, for the first 40% of hydrate dissociated, the two datasets fall almost on top of each other. However, after 40% dissociation, deviation occurs. The hypothesized reason for this deviation is the differences in the plugs. Because the nitrogen will take the path of least resistance through the plug, the exact dissociation of each hydrate sample will differ. Results and observations from the experiments revealed a conceptual picture for hydrate dissociation with nitrogen purging, which is distinct from either the electrical heating or depressurization method. As shown in Figure 8, hydrate plugs purged with nitrogen crumble into small loose fragments up to about 1 in. in size (via channel formation, as shown in Figure 4), as opposed to the shrinking core via radial dissociation observed in electrical heating or depressurization experiments.5,12 In Figure 8, there is no visible frozen water at the bottom of the cell, as seen in Figure 4. This is due to two reasons. The first was that the cooler the cell was placed in for liquid nitrogen quenching was too short to insert the cell in horizontally; therefore, the cell had to be placed at an angle that resulted in some of the water being drained to the bottom at the far end of the cell. Another explanation is that the free water was absorbed into the pore space of the hydrate. Modeling. To model the hydrate dissociation process, a number of assumptions were made as follows: (1) uniform constant temperature throughout the plug, (2) uniform constant pressure throughout the plug, (3) the surface of the hydrate was in 2575
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Figure 10. Model fitted (lines) to dissociation data (points) for sI hydrate in the long cell at 700 psig by adjustment of the mass-transfer coefficient K. The dashed line at 50% is used to guide the eye to see where the model was fitted.
Figure 9. Conceptual picture used for modeling hydrate dissociation via nitrogen purging. Not shown to scale.
equilibrium with the gas phase, (4) the gas flow rate was constant, (5) there was no water accumulation, (6) flow was distributed uniformly over the entire surface area of the hydrate, (7) only one channel grew in the center of the plug, and (8) tortuosity of the channel was equal to 1. With these assumptions, the simplified conceptual picture for hydrate dissociation via nitrogen purge was generated, as shown in Figure 9. The mass balance on the gas phase for methane is in out þ generation ¼ accumulation Dn Ci 1 vi 1 Ci vi þ KAðCeq Ci Þ ¼ Dt
ð1Þ
where Ci is the concentration of methane in segment i of the channel, Ceq is the thermodynamic equilibrium concentration of methane at the experimental T and P, vi is the flow rate of gas in segment i, K is the overall mass-transfer coefficient, A is the surface area, n is the number of moles of methane accumulated, and t is the time. For sII hydrates, it was assumed that the hydrate dissociated in the stoichiometric ratio of methane to ethane in the hydrate, which was confirmed via GC measurements.20 Using the explicit numerical method for solving the concentration, the concentration of methane was calculated along the hydrate plug over time. Next, the amount of hydrate dissociated was calculated using eqs 2 and 3 to calculate the number of moles of methane released into the gas phase by dissociation (Δni) and, subsequently, the volume of hydrate dissociated (ΔVi) Δni ¼ KAΔt ðCeq Ci, t Þ ΔVi ¼
Δni MW Fxmethane
ð2Þ ð3Þ
where MW is the molecular weight of the hydrate, F is the density of the hydrate, and xmethane is the mole fraction of methane in the
Figure 11. Model prediction of dissociation data for sI hydrate in the short cell at 2000 psig and the long cell at 1000 psig, with K = 2.0 107 m/s.
hydrate. After the volume of hydrate dissociated was calculated, the radius of the channel was updated. The following expression was used to calculate the radius of the channel at the next time step: rffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffi ΔVi ð4Þ rci, t þ Δt ¼ rci, t 2 þ επΔx where ε is the porosity of the hydrate and Δx is the grid space for segmenting the system (in the model, Δx was set to 1% of the total plug length). For the model, the value of the porosity was taken from experimental data and the value for the diameter of the hydrate particles was assumed to be 300 μm. Hydrate Dissociation Modeling. The mass-transfer model was fitted to the percent hydrate dissociation as a function of time. The percent dissociation calculated from the model was compared directly to the measured dissociation times from the experiments. The model predictions are in reasonable agreement with the experimental data at the early stages of dissociation for the sI experiments. The model predicts shorter dissociation times than observed experimentally for sII hydrate at 700 psig. From Figure 6, it can be seen that all four dissociation experiments require approximately the same time to reach 50% dissociation. The implications of this is that the model will take into account the pressure difference in the driving force, but from the experiments, it does not appear that 2576
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The model was then compared to sII hydrates, and as for sI hydrate, the overall mass-transfer coefficient was adjusted as a fitting parameter. Figure 12 shows the model fitted for sII hydrate dissociated at 2000 psig in the long cell. Figure 13 shows the model prediction for sII hydrates at 700 psig. The model fits reasonably well for the early stages of dissociation (
