Experimental Study on Feasibility of H2 and N2 as Hydrate Inhibitors

Article pubs.acs.org/jced

Experimental Study on Feasibility of H2 and N2 as Hydrate Inhibitors in Natural Gas Pipelines Emmanuel O. Obanijesu,*,† Ahmed Barifcani,‡ Vishnu K. Pareek,† and Moses O. Tade† †

Department of Chemical Engineering and ‡Department of Petroleum Engineering, Curtin University, Bentley Campus, Perth, Western Australia, 6102, Australia ABSTRACT: This study applied the temperature search method to investigate the feasibility of pure H2 and N2 gases to inhibit hydrate formation along the subsea natural gas pipeline networks. Hydrates of different mix ratios from CH4 and CO2 were initially formed in a cryogenic sapphire cell to study the component interactions. Each experiment was then repeated by adding either H2 gas or N2 gas to each of the mixes. The component interaction study showed that the risk of hydrates promotion increased with an increase in CH4 content of natural gas. It was discovered that a gas mix of (0.1 CO2 + 0.9 H2) mole fraction did not form hydrate at all pressures up to 20 MPa while that of (0.2 CO2 + 0.8 H2) mole fraction formed at −2 °C at a pressure of 10 MPa. The inability of (0.1 CO2 + 0.9 H2) mole fraction to form hydrate may be due to insufficient CO2 molecules filling the clathrate cage at that particular concentration. Furthermore, all the (CH4 + CO2) mixes formed hydrates and the (0.9 CH4 + 0.1 CO2) mole fraction showed a significant trend at 11 MPa and above. Again, introduction of both N2 and H2 gases to an earlier studied (CH4 + CO2) mix revealed their ability to inhibit formation of hydrate, but H2 showed higher significant effects. This was ascribed to the pressure conditions at which each form hydrate. Conclusively, this study confirmed that the addition of either of the gases will either prolong the formation of hydrate during operation or prevent the agglomeration of formed hydrate. This allows successful transportation of the hydrocarbon which enables the industry to operate at any desired pressure and still control the hydrate formation. Hence, the flow restriction on the operating conditions will be minimized without negative impact on the net profit margin except for the additional initial capital investments resulting from the proposed recommendations from this study.

1. INTRODUCTION Hydrate prevention along the subsea gas pipelines remains of paramount interest to flow assurance engineers because of the severe consequences of hydrate formation. Gas hydrates are easily formed along the subsea pipelines owing to interactions between the available water (H2O) and the gas components at the thermodynamically favored operating conditions of low temperature and high pressure.1 During transportation of the gas, hydrogen bonds in the available H2O molecules make them align as a host in a regular orientation which is stabilized by the guest (or former) molecules present in the gas through the van der Waal forces to precipitate a solid mixture known as hydrate.2 Hydrates are grouped into types I, II, and H as defined by their structures, but types I and II are most encountered in natural gas pipelines. Type I has dodecahedron (12-sided polyhedron) and tetrakaidecahedron (14-sided polyhedron) structures and is generally formed by CH4, C2H6, CO2, and H2S molecules, etc.3,4 It consists of 14 water molecules with the theoretical formula of X.53/4 H2O where X is the former. Type II, with dodecahedron and hexakaidecahedron (16-sided polyhedron) structures are formed by N2, C3H8, and i-C4H10 molecules and consists of 136 water molecules with X.52/3 H2O and X.17 H2O as theoretical compositions.5,6 While N2 occupies both the small and large cages, C3H8, and i-C4H10 only occupy the large cages because of their sizes. Type H can only © 2014 American Chemical Society

be formed in the presence of two formers, which are small molecules (mainly methane) and large molecules such as 2methylbutane, 2−2 dimethylbutane, and cyclohexane; however, these large molecules are rarely found in natural gas. Size-wise, the CH4, H2S, and CO2 have a molecular size range of (0.44 to 0.54) nm which is small enough to occupy both the small and large cages to form type I hydrate. C2H6 also forms type I hydrate but falls within the next region of (0.56 to 0.58) nm to occupy the large cage alone. C3H8 and i-C4H10 with a size range of (0.60 to 0.69) nm only occupy the large cages to form type II. The three conditions enhancing the formation of hydrate are turbulence (velocity and agitation), nucleation sites, and free water.7−9 These conditions are readily available during gas transmission in pipelines. Gas is normally transported at high pressure which gives rise to high velocity and agitation along the pipe-length. At some instances, the gas will flow through narrow points such as the choke valves where a sudden temperature drop will be experienced due to the Joule Thompson effects to promote hydrates formation.10 Good nucleation sites are provided by the welded spots (elbows and tee), dirt, scales, slits, and sands, while free-water from the Received: July 8, 2014 Accepted: October 7, 2014 Published: October 20, 2014 3756

dx.doi.org/10.1021/je500633u | J. Chem. Eng. Data 2014, 59, 3756−3766

Journal of Chemical & Engineering Data

Article

Figure 1. Schematic of the sapphire cell for liquid−gas interaction (Obanijesu et al., 2014).

cheaper is dangerous to store in a confined place such as offshore rigs due to its high flammability.15 Injection of methanol for hydrate prevention that annually costs the industry an estimated value of over $500,000,00016 can also form azeotropes with some of the gas components such as propane and butane,17 thus making binary distillation impossible as a separation option. It can easily dissolve alcohol-based corrosion inhibitors to initiate an unexpected corrosion problem along the line.18 Furthermore, a small quantity of air from the atmosphere usually dissolves into methanol during its storage to promote corrosion along the line. Acetone is expensive and promotes hydrate at low concentration. It can only inhibit at high concentrations, thus making it very costly as an inhibitor.19 Ammonia is toxic20,21 and can also react with CO2 and H2S in the aqueous phase. There is therefore a need to find inhibitors that could be process friendly, easy to regenerate, and cost-effective. The three requirements for hydrates to form are the conducive thermodynamic condition of low temperature and high pressure (or temperature−pressure relationship), presence of a former (guest), and water availability in required quantity. Technically, one of these requirements must be eliminated to prevent hydrate formation. Apart from being the desired products, formers cannot be removed from the reservoir. Also, efforts to minimize the amount of H2O produced with the gas from reservoirs have proved extremely difficult.22 Studies are therefore generally targeted toward the temperature−pressure relationship. The investigation of Snell et al.23 centered on the initial hydrate conditions for C2H4−H2O and CH4−C2H4− H2O systems and was finally compared to the experimental and predicted hydrate forming conditions for several mixtures of CH4−C2H4−C3H6−H2O hydrate formation systems. Also, Ma et al.24 used the “pressure search” method to study the CH4 + C2H4 and CH4 + C3H6 interactions in a cylindrical transparent sapphire cell and finally presented valuable data that could be used to test the existing hydrate models and software. Furthermore, Fray et al.25 measured three-phase (ice + clathrate hydrate + vapor) equilibrium in a water system with xenon

reservoir provides the water−gas interface required. If not quickly removed, the entrained hydrate-encrusted water droplets, initially formed as tiny particles would grow and agglomerate into larger hydrate mass. This leads to an increase in the slurry viscosity which finally plugs the line. The plugged inner orifice of a subsea pipeline results in pressure build-up within the transfer line and its eventual collapse; thus, exposing the operating personnel, equipment, and environment to severe safety risk. The pipeline industry annually spends billions of dollars to mitigate safety and environmental problems resulting from gas hydrate; subsequently, (10 to 15) % of the production cost is invested toward its prevention/minimization. Further, hundreds of millions of dollars is annually devoted on its prevention with half spent on inhibitions. Also, over $1 million and $2−4 million are respectively spent annually on continual removal of hydrate plugs from an onshore well and an offshore pipeline.11 Offshore operators additionally spend approximately $1 million per mile on pipeline insulation along subsea pipelines.12 Furthermore, millions of dollars are annually invested into research and development on hydrate prevention and minimization. Researchers have developed chemicals that are capable of inhibiting its formation and/or prevent its agglomeration. These chemicals, generally categorized into thermodynamics, kinetics, and anticoagulants (or antiagglomeration) based on their inhibiting techniques are however either expensive to apply, have severe side effects on the process, or have regeneration as well as disposal problems.13 Application of the kinetic hydrate inhibitors generates solid wastes that have to be properly managed to prevent further environmental consequences.14 Thermodynamic inhibitors are ionic salts and polar solvents of alcohols and glycols. At individual certain concentrations, these chemicals effectively shift the thermodynamic equilibrium by depressing the freezing point through lowering formation temperature or increasing the pressure. Methyl ethylene glycol (MEG) which is the most commonly used alcohol is very expensive, whereas methanol that is 3757



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(Xe), CO2, and CH4 as guest species. The generated results were used to determine the empirical laws that could be used to calculate the equilibrium pressure of pure clathrates at all temperatures. Using the “pressure search” method, Li et al.26 also reported the ability of tetrabutyl ammonium bromide to remarkably reduce the equilibrium hydrate formation pressure of CO2 + H2 hydrate. This very study combined the component interaction and temperature search methods to investigate the ability of pure hydrogen (H2) and nitrogen (N2) to inhibit hydrate formation.

Table 2. Measured Values for a Gas Mixture of (0.8 CH4 + 0.2 CO2) Mole Fractiona E/g E + H2/g H2/g E + CO2/g CO2/g p/MPa PT/MPa, H2 PT/MPa, CO2

2. METHODOLOGY 2.1. Materials and Equipment. The equipment description and setup for this study have been extensively described in Obanijesu et al.27 All experiments were conducted in a cylindrical cryogenic sapphire cell (Figure 1), and the gases used are given in Table 1. The CH4 + CO2 mixtures, CO2 + H2

gas

quality

CO2

industrial grade industrial grade industrial grade industrial grade Milli-Q water

CH4 N2 H2 H2O

BOC Australia, Perth, Australia

0.99995


0.999


0.995


ultrapure water

Curtin University, Perth, Australia

nCO2 nH2

PH2

=

nCO2 nH2

1359.20

5.74

5.39

1377.79 18.59 2.72

10.86 2.72

mCO2

=

MCO2 mH2 M H2

=

mCO2 M H2 MCO2 m H2

(2)

where Pn is the pressure of gas component n (MPa); nn is the number of mole of component n (mol); mn is the weight of the gas n filled into the cylinder (mass difference); and Mn is the molar mass of component n. 2.3. The Experiment. The first set of studies was conducted on pure CH4. A 5 mL aliquot of Milli-Q water was first injected into a thoroughly vacuumed sapphire cell for the liquid phase; the prepared gas was then fed into the system. The gas−liquid system was then pressurized to 10 MPa and heated to 25 °C. The initial minimum operating temperature for the experiment (Tset) was set to 15 °C, and the experiment commenced by switching on the chiller for gradual cooling. The Tset was gradually reduced each time the system’s temperature approached the initially set value. The chiller was switched off immediately when the first hydrate particles were noticed. The formation temperature was recorded, and the hydrate behaviors were visually observed. The beginning and end of the dissociation studies on the same gas were then carried out as explained in section 2.4. The experiments were repeated for the gas (CH4) at 12.5 MPa, 15 MPa, 17.5 MPa, and 20 MPa, respectively. The system was then purged, vented, and cleaned. The same sets of experiments were repeated for pure CO2 gas, CO2 + H2, CH4 + CO2, CH4 + CO2 + N2, and CH4 + CO2 + H2. For data validation, the experiment for each studied composition was conducted twice and the average was used for discussion. 2.4. The Beginning of Dissociation and End of Dissociation Studies. The beginning of the dissociation point is the temperature at which the first hydrate particle turns to liquid, while the end of dissociation is that point at which the last hydrate particle becomes liquid. The study on the beginning of dissociation commenced immediately after the complete solidification of the hydrate. This was conducted by switching off the chiller to prevent a further supply of external cooling effects to the system. The surrounding then started transferring heat to the enclosed system which led to its temperature rise until dissociation began. The temperature at which the first liquid was formed was recorded as the beginning of dissociation, while the temperature at which the last hydrate disappeared was recorded as the end of dissociation. 2.5. Instrumental Analysis of Gas Composition. Though the composition of each gas mix was mathematically estimated twice before filling the system for each experiment,

mixtures, CH4 + H2 mixtures, CH4 + CO2 + N2 mixtures, and CH4 + CO2 + H2 mixture were individually prepared in the laboratory as described in section 2.2. CH4 and CO2 gases were mixed at different ratios for the first set of experimental studies while H2 and N2 were subsequently added (one at a time) to the same gas ratios and normalized for further investigations. Initial investigations using CH4 and CO2 only were carried out to establish the present real-life subsea operation situation while THE addition of pure H2 and N2 gases to the exact mixes allows studying the impacts each gas has on the same subsea scenario. 2.2. Gas Mix Preparation. To prepare any particular gas, an empty 500 mL cylindrical steel bottle was first vacuumed and weighed with a digital balance. An amount of the gas, estimated by pressure ratio as given in eq 1 was then transferred from its main cylinder with an electrical transducer into the vacuumed bottle. The filled bottle was reweighed with an electronic balance. Equation 2 was then applied for the mole ratio to confirm the precision of the fill (Table 2) and the measured gas transferred into the sapphire cell that already contained 5 mL of milli-Q H2O. This same procedure was followed for all other gases except CO2 which was initially heated to 60 °C before filling in order to prevent it from undergoing partial condensation during experimentation. PCO2

cylinder 3

1597.50 1599.21 1.71

E is the weight of the empty cylinder, p is the cylinder pressure after filling and PT is the total pressure. Standard uncertainty in the measured mole fraction is 0.011.

source

0.999

cylinder 2

1276.98 1278.68 1.70

a

Table 1. List of Some of the Materials Used for the Study and Their Sources mole fraction purity

cylinder 1

(1) 3758



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Figure 2. Hydrate formation pattern for a gas mix of (0.2 CO2 + 0.8 H2) mole fraction.

this study further conducted the third compositional analysis instrumentally after each experiment. This is necessary to compare the initially estimated values with actual values for error estimation and validation of the generated data sets. The gas transmitter used for the analysis was a PolyGard (R) transmitter manufactured by MSR in Germany with serial number no: 38/08. It was an AT-A2-3400-4-001 model with 100 % vol. CH4. It had an alarm controller system also manufactured by the same company with model MGC-03-02− 02-9-110005011 and serial number 03-31/08. The equipment had a rating of 230 V, AC/0.1VA and input of 4−20 mA. For each analysis, a rubber tube was connected from the outlet point of the sapphire cell to the inlet point of the gas transmitter. The gas inside the cell was then gradually discharged for a flow into the transmitter to read. The gas composition, displayed in percentage was recorded, and the value was compared to the previous estimated value for precision. Data reliability between the predetermined (or calculated) gas mix ratios and instrumental readings was statistically analyzed using eq 3. ⎛1 SN = ⎜⎜ ⎝N

⎞1/2 ∑ (xi − xm) ⎟ ⎠ i=1 N

A pressure test was carried out on the cell each time the system was decoupled for a gas mix change or cell replacement after each industrial cleaning. This test was necessary ensure that the system was leak-proof, since a leak within the system will allow the discharge of hazardous gases to the environment. Also, a leak can cause an explosion in the laboratory when the experiment is operating at high pressure. For each pressure test, the system was coupled back, vacuumed, filled with N2 gas, and pressurized at 15 MPa for 30 min. If there was a leak, there would be a pressure drop and the exact location could be traced selectively. 2.7. Uncertainty of Measurements. The sapphire cell’s uncertainty of measurements for pressure and temperature were ± 0.05 MPa and ± 0.1 °C, respectively. The uncertainty of measurements for the electronic weighing balance was ± 0.001. Each measuring cylinder’s uncertainty of measurements for pressure and gas composition were ± 0.01 MPa and ± 1 g, respectively. Finally, the uncertainty of measurement on the mole fraction of the gas compositions as calculated through standard deviation was 0.0115 with a 0.96 confidence level.

3. RESULTS AND DISCUSSIONS 3.1. Individual and Combined Characteristics of CO2 and CH4 Hydrates. These studies are very significant considering the general industrial and domestic demands for sales of gas with ≥ 96 mol % CH4 composition for its high caloric value. This demand has pushed the gas industry into measuring gas quality purely based on its CH4 content. Thus, a gas field with higher CH4 content reduces the purification cost and increases the profitability for the industry. However, sweet gas fields mostly contain CH4 and CO2 with traces of other components; hence, there is a need to understand the impacts of their interactions on hydrate formation during transportation. 3.1.1. Hydrates from CO2 as the Only Guest. It was observed that a gas mix of (0.1 CO2 + 0.9 H2) mole fraction did not form hydrate even at a very high pressure of 20 MPa, whereas that of (0.2 CO2 + 0.8 H2) mole fraction formed hydrate at −2 °C at a pressure of 10 MPa (Figure 2). It may then be concluded that in the absence of any other hydrate former, CO2 alone at a very low concentration could not form a hydrate. This result is justified based on the available amount of the former (CO2). The inability of (0.1 CO2 + 0.9 H2) mole fraction to form a hydrate may be due to the unavailability of sufficient CO2 molecules to fill the clathrate cage at that

2⎟

(3)

S is the standard deviation, N is the sample number, xi is generated/experimental values, and xm is the mean value. 2.6. Precautions. The cell was regularly sent for industrial cleaning. This is necessary since it had to be fed with different gas mixtures for each major experiment. Introduction of different gas mixes will discolor the glassware over time and make visual observation almost impossible. Previous studies with the equipment confirmed that continuous introduction of different gas mixes into the cell without proper cleaning introduces dirt.27,28 The dirt accumulates and blurs the glassware, thus serving as a source of error during reading. Since each gas mix was studied at five different pressures, the first experiment was conducted at the highest pressure. The next study was then conducted at the immediate lower pressure by dropping the pressure and heating the system to 30 °C, at which it was left to stand about 2 h before the next experimentation. Heating to such a temperature released all the dissolved gas from the liquid phase to the gaseous phase, while the 2 h time lag allowed both the liquid and gaseous phases to be at equilibrium with one another before the next experiment. 3759



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Figure 3. Effects of CO2 concentration on methane hydrates: ×, CH4; ■, 0.8 CH4 + 0.2 CO2;

▲,

0.9 CH4 + 0.1 CO2; ⧫, 0.78 CH4 + 0.22 CO2.

sparingly soluble. Apart from the right molecular size, the guest gas molecule should not be highly soluble in water;29,30 that is why ammonia (NH3) and hydrogen chloride (HCl) could not form hydrates despite having small molecular sizes; they are highly soluble in water.18 3.1.4. Hydrates from CH4+CO2 Mixtures. All the (CH4 + CO2) mixed compositions with mole fractions of (0.9 CH4 + 0.1 CO2, 0.8 CH4 + 0.2 CO2, and 0.78 CH4 + 0.22 CO2) formed hydrate at all the investigated pressures (Table 3). It

particular concentration. Though the CO2 molecular size of (0.44 to 0.54) nm18 is small enough to occupy both the small and large cages to form type I hydrate; the amount of particles present in the (0.1 CO2 + 0.9 H2) mole fraction however is not sufficient enough to completely fill up the microcavities of the crystal lattice provided by the host water. However, the amount of available CO2 particles increased with concentration, enough to form hydrates at (0.2 CO2 + 0.8 H2) mole fraction. This observation particularly confirmed the importance of concentration of the guest species in hydrate formation study. It was further observed that the hydrate particles started to form inside the liquid at all pressures and traveled to the interphase. The hydrate growth rate of the (0.2 CO2 + 0.8 H2) mole fraction was very slow, and the particles were independent of one another even at 20 MPa and 0 °C. The accumulated hydrate particles formed “cornflakes” like slurries and suspended at the interphase. While the hydrates were pronouncedly noticed at 15 MPa and above, it was hardly noticed at 12.5 MPa and was formed below 0 °C at 10 MPa. Observation for the (0.2 CO2 + 0.8 H2) mole fraction at all pressures showed hydrates to be thinly deposited at the wall of the glass with the remainder rotating within the liquid phase. The stirring rate was vigorously increased to study the impact of agitation, but no difference was observed. 3.1.2. Hydrates from CH4 as the Only Guest. As presented in Figure 3, the study on pure CH4 gas showed that the gas forms hydrate at all concentrations and pressures. Hydrates formed from CH4 were whitish like snow and formed at the interphase as tiny flocs. At all pressures, the hydrate particles built-up downward into the liquid and rapidly agglomerated to produce a slurry which solidified to block the whole orifice within 5 min at 10 MPa and 3 min at 20 MPa. This is in agreement with the literature that hydrate agglomerate faster with an increase in pressure. 3.1.3. Impact of Solubility on Hydrate Formation. The difference in the hydrate formation potentials for both gases as observed in the laboratory is justified considering their solubility properties. Despite that both CH4 and CO2 have molecular sizes within the same range of (0.44 to 0.54) nm, CH4 has a very strong ability to form hydrate compared to CO2, because CO2 is readily soluble in water, whereas CH4 is

Table 3. Effects of Component Concentrations on Gas Hydrate Temperature (0.96 Level of Confidence) pure CH4

0.78 CH4 + 0.22 CO2

0.8 CH4 + 0.2 CO2

0.9 CH4 + 0.1 CO2

P/MPa

T/°C

T/°C

T/°C

T/°C

10 12.5 15 17.5 20

11.0 11.1 12.3 12.8 14.7

9.8 10.9 11.9 12.9 13.5

8.7 9.9 10.5 11.1 11.2

10.1 12.3 13.6 14.4 15.2

was observed that the formation temperatures for 100% CH4 at all studied pressures were higher than those for mixes of (0.8 CH4 + 0.2 CO2, and 0.78 CH4 + 0.22 CO2) mole fractions. This however was not the case for the mix with (0.9 CH4 + 0.1 CO2) mole fraction which observed the same trend below 11 MPa but became higher than formation temperatures of pure CH4 above 11 MPa (Figure 3). The change of (0.9 CH4 + 0.1 CO2) mole fraction mix at 11 MPa might indicate that the hydrate-forming ability of the CO2 gas became active at about 11 MPa when mixed with CH4 gas. This explains the higher formation temperatures for the mix compared to that of pure CH4 hydrates at the remaining pressures above 11 MPa, which could be attributed to the combined property effects of the two guests on the hydrate formation point. However, this is not so for the other studied mixes (0.8 CH4 + 0.2 CO2 and 0.78 CH4 + 0.22 CO2 mole fractions) that exhibited lower hydrate temperature throughout the whole studied pressures. This could be due to the increase in the CO2 concentration in the mix which reduces the quantity of CH4 molecules occupying the clathrate hydrates cage. 3760



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Figure 4. Hydrate agglomeration trend for a gas mix with (0.9 CH4 + 0.1 CO2) mole fraction at 20 MPa and 5 °C.

Figure 3 further showed that the hydrate formation temperatures for (0.78 CH4 + 0.22 CO2) mole fraction were higher than those of (0.8 CH4 + 0.2 CO2) mole fraction at all pressures. No immediate explanation could be given for this, but it might have to do with CH4 concentration which was now decreasing; thus, enabling the hydrate promotional ability of CO2 hydrate to take over. Also, the difference in the hydrate formation points at each pressure is significantly large despite the slight variation of 2% in the gas mix concentration. This difference even increased with pressure to give more credence to the ability of CO2 gas to have greater hydrate promotional tendencies at higher pressures. Considering the variation in gas composition from field to field, this observation is highly important in assisting the prediction of the hydrate expectations from a field based on the gas composition. Hydrates from the (0.9 CH4 + 0.1 CO2) mole fraction were formed within the water body but quickly traveled to settle at the water−gas interphase. The hydrate growth rate at all pressures was observed to be significantly high, with the hydrate cloud usually formed within the water body and rapidly traveling to the interphase to join the existing hydrate particles for fast agglomeration. At 20 MPa and a Tset of 5 °C, the entire liquid turned to hydrate and completely blocked the orifice within 8 min of spotting the first hydrate particle (Figure 4), and the stirrer stopped 3 min afterward. This showed that gas within this compositional value could be extremely troublesome for the pipeline industry during the winter period, and at all times for subsea pipelines considering that the sea temperature is only 4 °C or below. The agitation rate was significantly increased at 17.5 MPa to study its effects and it was observed that the already formed hydrates quickly dissolved back into the liquid. This showed that high agitation rate breaks the tension at the interphase to allow more interaction between the liquid and gaseous phases. This allows more gas molecules to dissolve in the liquid to produce larger hydrate block. This is a very significant and dangerous issue along transmission pipelines since industry operates at high pressures that promote agitation significantly. 3.2. Effects of N2 and H2 Gases on Hydrate Formation Points. 3.2.1. Preliminary Studies: Effects of Pure H2 Gas on CH4 Hydrates. Results from the preliminary investigations on the ability of pure H2 gas to shift the formation temperature of methane hydrate are given in Table 4a,b. An encouraged outcome allows for further studies to investigate the impacts of concentration variations and the results presented in Table 4 b,c. The results obtained showed a very strong ability of pure H2 gas to inhibit methane’s hydrate formation temperature as shown in Figure 5. At all the investigated pressures, the temperature of the hydrate formation point was remarkably reduced when H2 gas was added. This could be attributed to the fact that pure H2 gas forms Type II clathrate hydrates at a

Table 4. Effects of H2 on Methane Hydrates Formation Temperature (0.96 level of confidence) P

CH4a

0.83 CH4 + 0.17 H2b

0.74 CH4 + 0.26 H2c

MPa

T/°C

T/°C

T/°C

10 12.5 15 17.5 20

11.0 11.1 12.3 12.8 14.7

6.6 7.9 8.7 9.4 10.6

6.8 8.0 9.5 10.7 11.1

very high pressure and low temperature of 220 MPa and 249 K, respectively;31 while it forms hydrate at 300 MPa and 280 K in the presence of second guest component.32 Since methane as the second guest component in this gas mix is highly desired, its hydrate formation point is drastically reduced as the result of its interactions with H2 gas which is inert at the studied operating conditions. It was also observed that the introduction of H2 gas strongly discouraged agglomeration of the hydrates. The hydrates appeared thinly within the liquid and traveled with a very low agglomeration rate in the direction of water flow. The agglomeration rate was very insignificant at 10 MPa and 12.5 MPa. To study the sea condition, the system temperature was dropped to 0 °C at each pressure while the agglomeration condition was continually monitored. Despite this extremely low temperature, the hydrate growth rate was still very slow (Figure 6). Furthermore, as a result of the reducibility/inhibition property shown by H2, the formation temperature was expected to further reduce when its concentration in the gas mix was increased; contrarily, this was not the case as can be observed in Figure 5. This suggested the possibility of optimal effective concentration for the inhibition ability. 3.2.2. Further Studies: Effects of N2 and H2 on the Natural Gas Hydrate Formation Point. Following the confirmation that H2 could inhibit the formation of CH4 hydrates, further studies were conducted to individually investigate the effects of N2 and H2 on the hydrate formation point of sweet natural gas. For the first study, N2 was added to the initially studied (CH4 + CO2) and the total composition was normalized. The normalized gas mixture was then fed into the sapphire cell and studied at the five pressures for hydrate formation temperatures, beginning of dissociation, and end of dissociation. The cell was then thoroughly cleaned and vacuumed, and the same experimental studies were repeated on the same amount of H2 gas. Again, model equations were developed by the curve fitting method and regression analysis for each of the experimental data set. The coefficient of determination (R2) represented in eq 4 was used to compare the degree of fitting to the experimental data. 3761



Figure 5. Effects of H2 concentration on methane hydrates:

Article

▲,

CH4; ⧫, 0.83 CH4 + 0.17 H2; ■, 0.74 CH4 + 0.26 H2).

Figure 6. Hydrate agglomeration trend for a gas mix with (0.83 CH4 + 0.17 H2) mole fraction at 20 MPa and 0 °C.

R2 = 1 −

∑ (yi − fi )2

Table 6. Inhibition Effects of N2 and H2 on Natural Gas Hydrate Formation Temperature (0.96 Level of Confidence)

2

∑ (yi − ym )

(4)

wher Σ(yi − f i)2 is the residual sum of squares; Σ(yi − ym)2 is the sample variance; f i is the observed value; yi is the actual experimental value; and ym is the mean of experimental data. Besides, a temperature−pressure relationship in the form of T = f(P) was generated and presented in Table 5 along with R2 values. Table 5. Predictive Relationships between Formation Temperature T and Pressure P for N2 and N2 Inhibition Potentials mole fraction

equation

R2

0.78 CH4 + 0.22 CO2 0.75 CH4 + 0.17 CO2 + 0.08 N2 0.8 CH4 + 0.04 CO2 + 0.16 H2

T = 0.0376P + 6.16 T = 0.044P + 4.74 T = 0.0248P + 6.56

0.9906 0.9733 0.9135

P

0.78 CH4 + 0.22 CO2

0.8 CH4 + 0.04 CO2 + 0.16 H2

0.75 CH4 + 0.17 CO2 + 0.08 N2

MPa

T/°C

T/°C

T/°C

10 12.5 15 17.5 20

9.8 10.9 11.9 12.9 13.5

8.7 9.9 10.5 11.1 11.2

8.8 10.6 11.4 12.6 13.3

type II hydrates. This could be attributed to the fact that H2 gas has better inhibition ability at all pressures due to its relatively lower formation temperature. Natural gas is transmitted at pressures sometimes above 30 MPa which implies that the addition of pure N2 gas to a subsea natural gas transmission line may still result in hydrates (but at a much lower temperature range compared to natural gas) since pure N2 forms hydrate at 24.5 MPa and 4 °C33 which is the sea temperature. Some subsea transboundary pipelines transmitting natural gas from one country to another even operate at a pressure range close to 55.7 MPa for economical breakeven. On the basis of the work of Mao and Mao31 and Florusse et al.32 however, pure H2 gas will remain inert at all natural gas transmission conditions, since the gas industry could not operate at such a pressure range close to 200 MPa for now. Observations during the experiments revealed that the hydrates from (CH4 + CO2 + N2) gas mixture were very tiny with low agglomeration rates. Agglomeration was hardly noticed at 10 MPa while the rate was almost ignorable at the other investigated pressure points up to 4° below the respective

The experimental results of individual effects as presented in Table 6 show that the two gases are able to remarkably reduce the hydrate formation temperature points at all the studied pressures. According to Bahadori,33 pure N2 gas forms hydrate between −1 and 13.2 °C for the pressure range between 14.4 and 55.42 MPa, respectively. This enables the gas to inhibit hydrate formation for the mixture since it relatively has lower hydrate formation points at all pressures compared to both CH4 and CO2 gases. This is also confirmed by the simple temperature vs pressure relationship shown in Table 5. Further observation however confirmed that the inhibition ability of H2 gas was very significant compared to that of N2 gas (Figure 7) despite that both have small molecules and can form 3762



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Figure 7. Effects of pure N2 and H2 gases on natural gas hydrate formation: ⧫, 0.8 CH4 + 0.2 CO2; ▲, 0.75 CH4 + 0.17 CO2 + 0.08 N2; ■, 0.8 CH4 + 0.04 CO2 + 0.16 H2.

Figure 8. Hydrate growth pattern for (CH4 + CO2 + N2) gas mix after initial formation (T = 4 °C, t = 300 min).

Figure 9. Hydrate agglomeration trend for (CH4 + CO2 + H2) gas mix at 20 MPa and 4 °C.

(CH4 + CO2) formation temperature. The hydrates were very distinct, and the liquid phase remained clear (Figure 8). Meanwhile, hydrates from the CH4 + CO2 + H2 gas mixture were very tiny with no agglomeration at all pressures (Figure 9). This property exhibited by the CH4 + CO2 + H2 mix was confirmed in the study conducted by Florusse et al.32 in which it was reported that hydrogen molecules in the clathrate usually remain unbounded with water and are still in a free rotational state within the clathrate cages. This is possible since the

molecules of pure H2 gas are very small and capable of easily leaking out of the cages. This will eventually reduce the amount that could be stored at a time and thereby prevent the formed hydrate from agglomerating. By extension, these individual properties affect their interactions with natural gas during the hydrate formation process and enables H2 gas to drastically reduce the formation temperature comparatively. The reduction percentage for each gas was calculated using eq 5. It could be seen from Figure 10 that the reduction ability 3763



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Figure 10. Hydrate inhibition potentials of H2 and N2 gases at different pressures: ⧫, H2; ■, N2.

of N2 decreases with an increase in pressure while that of H2 increases with pressure. FTCH4 + CO2) − FTCH4 + CO2 + G) FTCH4 + CO2)

Table 7. Results of Formation Temperature FT, Beginning of Dissociation Temperature BT, and End of Dissociation Temperature ET on Various Gas Mixtures (0.96 Level of Confidence)

100 (5)

P/MPa

FTi is the hydrate formation temperature for gas mix i; and G is the inhibiting gas in consideration (either H2 or N2). This further confirmed the preference of H2 gas as an inhibitor between the two; especially, at an extremely high pressure. The trend as observed in the Figure (10) may be due to the ability of H2 gas to form hydrate at higher pressures in the presence of other guest molecules.32 The observed downward and upward trend for the N2 gas in the figure may be due to diffusional resistance of the gas at higher pressures. At lower pressure, N2 molecules could move more easily between the hydrates. However, increasing the pressure causes the hydrate particles to become more compact and the proximity between the particles will decrease and result in an increase of the diffusional resistance to the N2 molecules. However, at these higher pressures, hydrogen molecules are still small enough to penetrate. Also, the experimental results as shown both in Table 7 and Figure 11 panels a−d confirmed that the hydrate formation temperature is almost equal to the temperature of the beginning of dissociation. This is thermodynamically correct since the heat loss by the system to the surroundings at the hydrate formation point (through the cooling process) should be equal to the heat gained at the same hydrate’s melting point.

10 12.5 15 17.5 20 10 12.5 15 17.5 20 10 12.5 15 17.5 20 10 12.5 15 17.5 20

4. CONCLUSIONS This study has successfully investigated the implications of component interactions on hydrate formation temperature. It was discovered that CH4 played key roles in the formation of hydrate during natural gas transportation; the higher was the CH4 content in the gas mix, the higher was the risk of hydrates promotion. The resulting CH4 hydrates grew very fast and blocked the pipe’s orifice within a short period of time. It was also discovered that in the absence of other formers, CO2 does not form a hydrate at low concentrations but has a remarkable ability to aid hydrate formation in the presence of CH4.

FT/°C

BT/°C

0.83 CH4 + 0.17 H2 6.6 6.7 7.9 8.0 8.7 8.7 9.4 9.4 10.6 10.6 0.8 CH4 + 0.2 CO2 10.1 10.2 12.3 12.3 13.6 13.6 14.4 14.5 15.2 15.4 0.8 CH4 + 0.04 CO2 + 0.16 H2 8.7 8.8 9.9 9.8 10.5 10.6 11.1 11.6 11.2 11.7 0.75 CH4 + 0.17 CO2 + 0.08 N2 8.8 8.7 9.3 9.3 11.4 11.6 12.2 12.2 13.3 13.4

ET/°C 10.70 12.8 14.10 15.30 16.10 13.8 15.8 16.8 17.4 18.5 10.6 12.9 14.9 15.0 16.2 12.9 14.6 16.0 16.9 18.2

The study further confirmed the ability of N2 and H2 to individually inhibit the formation of gas hydrate by significantly suppressing the formation points. However, H2 gas showed a higher inhibition ability by forming hydrates at very higher pressures which are not within the operating range of the industry. The gas also prevents hydrate agglomeration due to its smaller particle size that could easily leak out of the clathrate cages. Though this study confirmed H2 as a relative preference gas, further investigation covering safety factors, material availability, cost implication, and recovery ability from the 3764



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Figure 11. (■,◆) Formation, (▲) beginning, and (×) end of dissociation temperatures for the hydrate of (a) 0.83 CH4 + 0.17 H2 mole fraction; (b) 0.8 CH4 + 0.2 CO2 mole fraction; (c) CH4 + CO2 + H2 mole fraction; (d) CH4 + CO2 + N2 mole fraction.

prevented by recycling the gas after separation at the exit, although this will require additional pipelines which will increase production cost. Also, N2 gas can easily be separated from the natural gas compared to H2 gas. This means that after successfully transporting the natural gas through the pipeline system, more capital will be required to separate H2 gas from the stream; thus, adding to production cost. Again, passing H2 gas along the pipeline might be dangerous for the pipe since the gas can easily dissociate through partial pressure to initiate corrosion along the length of the pipe. Therefore, the properties of the materials of construction should be critically considered for process safety during the process design.

natural gas stream should be conducted before choosing an option from both. Finally, this study has established a new research area on hydrate inhibition which could be built upon through further studies. If established in the field, the use of either of these gases will annually save millions of dollars for the industry as a cleaner technology.

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RECOMMENDATION This study has experimentally confirmed the feasibilities of using both gases to inhibit hydrate formation in natural gas pipelines, further studies should however be conducted to confirm the practicality of the proposal. This is essential considering the need to source for the huge amount of H2 and N2 gases required. A possibility is to source for N2 gas from the atmosphere and H2 from steam reforming processes. These will however require many design possibilities considering material availability, cost implications, recovery from natural gas stream, and space availability among others. The study further suggested H2 as the preference gas comparatively; care must be taken however by considering the cost implications and reactivity properties of the two gases before finalizing on any option. From a general design angle, N2 can be continuously stripped from the atmosphere. Thus, the initial cost for installing a N2 process plant may be the only requirement, whereas H2 gas must be obtained through some complicated processes which include steam reforming. This means that application of H2 gas will include the initial installation cost and continual processing cost apart from other operational costs. Continuous processing of fresh H2 can be

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AUTHOR INFORMATION

Corresponding Author

* E-mail: [email protected]; [email protected]. Tel: +61414512670. Notes

The authors declare no competing financial interest. Dr. Emmanuel Obanijesu acknowledges the financial supports from Curtin University, Perth and Western Australian Energy Research Alliance (WAERA) through the Curtin Strategic International Research Scholarship (CSIRS), and AustraliaChina Natural Gas Technology Partnership Fund Top-up Scholarship schemes, respectively.

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Experimental Study on Feasibility of H2 and N2 as Hydrate Inhibitors

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