Embed Size (px)
Citation preview
Mississippi State University Mississippi State University
Scholars Junction Scholars Junction
Theses and Dissertations Theses and Dissertations
8-7-2004
Examination of the Effects of Biosurfactant Concentration on Examination of the Effects of Biosurfactant Concentration on
Natural Gas Hydrate Formation in Seafloor Porous Media Natural Gas Hydrate Formation in Seafloor Porous Media
Charles E. Woods
Follow this and additional works at: https://scholarsjunction.msstate.edu/td
Recommended Citation Recommended Citation Woods, Charles E., "Examination of the Effects of Biosurfactant Concentration on Natural Gas Hydrate Formation in Seafloor Porous Media" (2004). Theses and Dissertations. 2097. https://scholarsjunction.msstate.edu/td/2097
This Graduate Thesis - Open Access is brought to you for free and open access by the Theses and Dissertations at Scholars Junction. It has been accepted for inclusion in Theses and Dissertations by an authorized administrator of Scholars Junction. For more information, please contact [email protected].
EXAMINATION OF THE EFFECTS OF BIOSURFACTANT
CONCENTRATION ON NATURAL GAS HYDRATE
FORMATION IN SEAFLOOR POROUS MEDIA
By
Charles E. Woods, Jr.
A Thesis Submitted to the Faculty of Mississippi State University
in Partial Fulfillment of the Requirements for the Degree of Master of Science
in Chemical Engineering in the Dave C. Swalm School of Chemical Engineering
Mississippi State, Mississippi
August 2004
Copyright by
Charles E. Woods, Jr.
2004
EXAMINATION OF THE EFFECTS OF BIOSURFACTANT CONCENTRATION ON
NATURAL GAS HYDRATE FORMATION IN SEAFLOOR POROUS MEDIA
By
Charles E. Woods, Jr.
Approved:
_________________________________ ______________________________ Dr. Rudy E. Rogers Dr. Kirk H. Schulz Professor of Chemical Engineering Professor of Chemical Engineering (Director of Thesis) Earnest W. Davenport, Jr. Chair,
Director of Dave C. Swalm School of Chemical Engineering,
(Committee Member) _________________________________ ______________________________ Dr. Hossein Toghiani Dr. W. Todd French Associate Professor of Chemical Engineering Assistant Research Professor of (Committee Member) Chemical Engineering (Committee Member)
______________________________ Robert P. Taylor Interim Dean James Worth Bagley College College of Engineering
Name: Charles E. Woods, Jr.
Date of Degree: August 7, 2004
Institution: Mississippi State University
Major Field: Chemical Engineering
Major Professor: Dr. Rudy E. Rogers
Title of Study: EXAMINATION OF THE EFFECTS OF BIOSURFACTANT CONCENTRATION ON NATURAL GAS HYDRATE FORMATION IN SEAFLOOR POROUS MEDIA
Pages in Study: 128
Candidate for Degree of Master of Science of Chemical Engineering Various porous media were tested with biosurfactant solutions (rhamnolipid or
Emulsan) at concentrations ranging from 0 ppm to 1000 ppm. The biosurfactant
solutions in the presence of porous media often showed substantial gas hydrate
catalyzation, localization on selected surfaces, and/or specific hydrate form (massive,
stratified, dispersed.)
At 1000-ppm concentrations of rhamnolipid, all porous media surfaces exhibited
the same hydrate formation rate increase of 187% over the control. The curves generated
for rhamnolipid or Emulsan concentration versus peak hydrate formation rate resembled
certain classical adsorption curves.
Bentonite and aragonite showed hydrate catalyzation properties with or without
biosurfactants. The preference for hydrate formation on porous media surfaces (no
surfactant) was: Bentonite/nontronite > aragonite/stainless steel > Ottawa sand/kaolinite.
Porous media/biosurfactant concentration combinations play marked roles in the types of
gas hydrates formed: massive, dendritic, or needle-like. The research helps to explain the
vast occurrence of gas hydrates in ocean sediments.
-ii-
DEDICATION
I would like to dedicate this research and the culmination of this paper to my
parents, Charles and Barbara, my sister Amy, and especially to my understanding wife,
Marcia. Good things come to those who wait.
-iii-
ACKNOWLEDGMENTS
I would like to express my gratitude to all those who had a hand, directly or
indirectly, in the materialization of this study. I am indebted to Dr. Rudy E. Rogers for
his patience, dedication, and guidance through the many pitfalls of this project. I would
also like to thank my thesis committee of Dr. Kirk H. Schulz, Dr. Hossein Toghiani, and
Dr. W. Todd French for their time, effort, suggestions, and their inestimable help. I
would like to thank my coworkers, Jennifer Dearman, Ding Tao, and Dr. Gouchang
Zhang, for their rhetoric and support. Finally, I would like to show my deep appreciation
to all my friends and comrades, especially Transito Macias and Katrina Parker.
-iv-
TABLE OF CONTENTS
PAGE
DEDICATION.............................................................................................................. ii
ACKNOWLEDGMENTS ............................................................................................ iii
LIST OF TABLES........................................................................................................ vii
LIST OF FIGURES ...................................................................................................... viii
CHAPTER
I. INTRODUCTION................................................................................................. 1
II. LITERATURE REVIEW..................................................................................... 8
HYDRATE STRUCTURE ............................................................................................... 8 Structure I ............................................................................................................ 9 Structure II........................................................................................................... 9 Structure H .......................................................................................................... 10
GAS HYDRATE SOURCES ........................................................................................... 11 Thermogenic........................................................................................................ 12 Biogenic .............................................................................................................. 13
BIOSURFACTANTS...................................................................................................... 14 Rhamnolipid ........................................................................................................ 15 Emulsan............................................................................................................... 17
HYDRATE INHIBITION, PROMOTION, AND BIOSURFACTANTS..................................... 19 POROUS MEDIA.......................................................................................................... 20 POROUS MEDIA, SAND .............................................................................................. 21 POROUS MEDIA, CLAYS............................................................................................. 22
Kaolinite .............................................................................................................. 23 Bentonite ............................................................................................................. 24 Nontronite............................................................................................................ 27
POROUS MEDIA, MINERALS....................................................................................... 27
III. THEORETICAL BACKGROUND.................................................................... 29
SURFACTANTS ........................................................................................................... 29
-v-
CHAPTER PAGE
BIOSURFACTANTS...................................................................................................... 31 Rhamnolipid ........................................................................................................ 32 Emulsan............................................................................................................... 33
ADSORPTION THEORY................................................................................................ 34 Adsorption Classification.................................................................................... 34 Adsorption in Soils.............................................................................................. 37 Adsorption and Gas Hydrates ............................................................................. 38
INDUCTION TIME & NUCLEATION THEORY ............................................................... 39 GAS HYDRATE FORMATION RATE (KINETICS)........................................................... 41 PHASE EQUILIBRIA..................................................................................................... 43
Gas Gravity ......................................................................................................... 43 Distribution Coefficient Method ......................................................................... 44 Statistical Thermodynamics ................................................................................ 45
OVERALL MECHANISM .............................................................................................. 46
IV. EXPERIMENTAL METHODS ......................................................................... 50
HYDRATE EXPERIMENTAL SETUP .............................................................................. 50 HYDRATE PREPARATION............................................................................................ 54 ADSORPTION PREPARATION....................................................................................... 56 EQUIPMENT................................................................................................................ 58
Mass Balance....................................................................................................... 58 Constant Temperature Bath................................................................................. 59 Equilibration Bath ............................................................................................... 59 Sonicating Horn................................................................................................... 59 Surface Tensiometer............................................................................................ 60 pH meter .............................................................................................................. 60 Reaction Vessel ................................................................................................... 60 Sample Container ................................................................................................ 61 RTD probes ......................................................................................................... 61 Pressure Transducer ............................................................................................ 61 Linear Power Supply........................................................................................... 62 Pressure Relief Valve .......................................................................................... 62 Data Acquisition System..................................................................................... 62 Digital Camera .................................................................................................... 63
MATERIALS.............................................................................................................. 63 Rhamnolipid ........................................................................................................ 63 Emulsan............................................................................................................... 63 Ethanol ................................................................................................................ 63 Natural Gas.......................................................................................................... 64 Ottawa Sand ........................................................................................................ 64 Bentonite Clay..................................................................................................... 64 Kaolinite Clay ..................................................................................................... 64 Nontronite Clay ................................................................................................... 64
-vi-
CHAPTER PAGE
Aragonite ............................................................................................................. 65
V. RESULTS & DISCUSSION................................................................................ 66
SCOPE OF RESULTS .................................................................................................... 66 NATURAL GAS HYDRATE FORMATION RATE............................................................. 66 EFFECT OF BIOSURFACTANT CONCENTRATION ON FORMATION RATE....................... 70
Rhamnolipid Concentration Effects on Formation Rate ..................................... 71 Emulsan Concentration Effects on Formation Rate ............................................ 73
EFFECT OF POROUS MEDIA ON FORMATION RATE..................................................... 76 ADSORPTION OF BIOSURFACTANTS ON POROUS MEDIA............................................. 78 ADSORPTION AND BIOSURFACTANT CONCENTRATION RELATED TO FORMATION ..... 81 INDUCTION TIME........................................................................................................ 87 HEAT AND GAS TRANSFER EFFECTS ON FORMATION RATE ....................................... 90 EFFECT OF ELECTROLYTES ON FORMATION RATE ..................................................... 92 GAS HYDRATE IN POROUS MEDIA, PREFERENCE TRENDS ......................................... 93 GAS HYDRATE PACKAGING, BIOSURFACTANT ORDERING......................................... 96 DISPERSED SEDIMENT IN MASSIVE HYDRATES.......................................................... 99
VI. CONCLUSIONS ................................................................................................ 101
ADSORPTION.............................................................................................................. 101 FORMATION RATE..................................................................................................... 103 HYDRATE INDUCTION ............................................................................................... 104 STRUCTURE AND PREFERENCE.................................................................................. 104 SCIENTIFIC SIGNIFICANCE......................................................................................... 105 SUMMARY................................................................................................................. 106
REFERENCES ............................................................................................................. 107
APPENDIX
A. EXPERIMENTAL DATA................................................................................... 114
B. PENG-ROBINSON CALCULATIONS.............................................................. 127
-vii-
LIST OF TABLES
TABLE PAGE
2.1. Biosurfactant Classifications and Examples [26, p. 8] ..................................... 14
5.1. Experimental Matrix .......................................................................................... 67
5.2. Biosurfactant Selective Adsorption Test ........................................................... 79
5.3. Induction Time................................................................................................... 89
5.4. Effect of Electrolytes on Gas Hydrate Formation.............................................. 92
A.1. Experimental Plan ............................................................................................. 115
A.2. Surface Tension of Rhamnolipid at Room & Hydrate Temperature ............... 118
A.3. Surface Tension of Emulsan at Room Temperature ......................................... 118
A.4. Heat & Mass Transfer Effects on Hydrate Formation (Fig. 5.10) .................... 120
A.5. Effect of Rhamnolipid on Ottawa Sand, Averaged (Fig. 5.6)........................... 120
A.6. Effect of Rhamnolipid on Ottawa Sand/Bentonite, Averaged (Fig. 5.7).......... 121
A.7. Effect of Rhamnolipid on Ottawa Sand/Kaolinite, Averaged (Fig. 5.8)........... 121
A.8. Effect of Emulsan on Ottawa Sand, Averaged (Fig. 5.4) ................................. 121
A.9. Effect of Emulsan on Ottawa Sand/Bentonite, Averaged (Fig. 5.4)................. 122
A.10. Effect of Emulsan on Ottawa Sand/Kaolinite, Averaged (Fig. 5.4) ............... 122
A.11. Effect of Rhamnolipid on Varied Surfaces, Averaged (Fig. 5.3, 5.5) ............ 123
-viii-
LIST OF FIGURES FIGURE PAGE
2.1. Geometry of Gas Hydrates................................................................................. 11
2.2. Chemical Structure of Rhamnolipid .................................................................. 16
2.3. Emulsan Unit Structure [34] .............................................................................. 18
2.4. Structure of Sand................................................................................................ 21
2.5. Kaolinite Structure [47, p. 78] ........................................................................... 24
2.6. Sodium Montmorillonite Structure [47, p. 84] .................................................. 25
2.7. Aragonite Orthorhombic Structure [52]............................................................. 28
3.1. Adsorption Isotherms [69, p. B-278] ................................................................. 35
4.1. Diagram of Hydrate Sample Cup (Drawn to Scale) .......................................... 51
4.2. Hydrate Formation Cell Photograph.................................................................. 52
4.3. Diagram of Hydrate Reactor Vessel (Not to Scale)........................................... 53
4.4. Filled Sample Cup.............................................................................................. 55
5.1. Definition of Peak Formation Rate .................................................................... 69
5.2. Effect of Rhamnolipid Concentration on Gas Hydrate Formation Rate............ 71
5.3. Hydrate Formation Rate at 1000 ppm Rhamnolipid.......................................... 73
5.4. Effect of Emulsan Concentration on Gas Hydrate Formation Rate................... 74
5.5. Effect of Sediment on Peak Formation Rate in Distilled Water........................ 77
5.6. Rhamnolipid Concentration Vs Peak Formation Rate in Ottawa Sand ............. 82
5.7. Rhamnolipid Concentration Vs Peak Formation Rate in Bentonite Clay.......... 83
5.8. Rhamnolipid Concentration Vs Peak Formation Rate in Kaolinite Clay .......... 85
5.9. Induction Time in Gas Hydrate Growth ............................................................ 87
5.10. Effect of Heat and Mass Transfer Limitation .................................................. 91
5.11. Preference of Gas Hydrates to Stainless Steel Over Silica (OS) ..................... 94
-ix-
FIGURE PAGE
5.12. Preference of Gas Hydrates to Smectites......................................................... 95
5.13. Preference of Gas Hydrates to Aragonite with No Surfactant Present ............ 96
5.14. Gas Hydrate Packing Arrangements................................................................ 97
5.15. Nontronite Dispersed Within Hydrate Matrix ................................................. 99
A.1. CMC of Rhamnolipid at Room & Refrigerated Temperature .......................... 119
A.2. ST Vs Concentration of Emulsan at Room Temperature ................................. 119
-1-
CHAPTER I
INTRODUCTION
Gas hydrates are clathrate compounds consisting of gas molecules occluded
within an array of hydrogen-bonded water molecules. Unlike ice’s lattice structure, the
lattice of a gas hydrate crystal consists of a three-dimensional pattern characterized by a
preference for regular shapes such as pentagons and hexagons. These regular patterns
lessen the strain of the water bond angle of 104.5o most effectively. When introduced at
sufficiently high pressures and suitably low temperatures, gas molecules will, through
weak van der Waals forces, occlude into cavities of the hydrogen-bonded water network.
Gas hydrate structure has been likened to many naturally occurring patterns that
help in visualizing how the non-stoichiometric compound appears. Two such structures
are the buckminsterfullerene, or buckyball, and a common soccer ball. While
geometrically different, these patterns help to understand the construction of simple gas
hydrate molecules. Each shape, including gas hydrates, incorporates the use of regular
polygonal shapes to construct the surface of a hollow, cage-like structure. To date,
hydrates are known to appear as one of three common configurations or structures:
Structure I (sI), Structure II (sII), or Structure H (sH). These structures will be
considered in greater detail in the following chapter.
-2-
After 1810 when Sir Humphrey Davy discovered chlorine hydrates [1], gas
hydrates were considered for more than a century to be a laboratory curiosity with no
known natural occurrences. Gas hydrates did not draw much consideration until the
1930’s when the oil and gas industry started to detect icy deposits in many of their
pipelines, both above ground and sub-sea [2, p. 851]. These crystals were natural gas
hydrates that formed when moisture in the lines encountered cold temperatures of
surrounding environments or reduced temperature from Joule-Thompson expansion
cooling.
Gas hydrates have been discovered in abundance within sediment on the ocean
floor and in permafrost areas where temperatures and pressures are conducive. Gases
from these hydrates come from both geothermal and biological sources. As a matter of
fact, Brooks estimated that nearly half of the gas hydrates discovered in the Gulf of
Mexico was thermogenic while the other half was biogenic [3, p. 409]. Meanwhile,
Kvenvolden contends that gas hydrates from biological activity dominate in permafrost
areas [3, p. 409]. In addition, many microbial and subsea floor organisms such as tube
worms and mussels have been associated around or within gas hydrates [4, p. 5143; 5].
Within the last ten years, hydrates have acquired a significant amount of attention,
not only from the oil and gas industry, but also from such disciplines as chemistry,
chemical engineering, geology, oceanography, energy conservation, and environmental
engineering. Gas hydrates play a significant role in many natural phenomena such as
seafloor stability. Carbon dioxide sequestration and natural gas storage in gas hydrates
hold promise for significant societal benefits. Gas hydrates might also be a means to
recover natural gas resources, demineralize water, and predict global temperature
-3-
changes. The potential exploitation of some facets of gas hydrates or benefits from
hydrate prevention in other cases make gas hydrates a very interesting and productive
topic.
One area that may effectively be exploited in the near future is the recovery of
natural gas from seafloor and permafrost gas hydrates or “hydrate farming.”
Conservative estimates of natural gas present in seafloor hydrates reveal that
approximately twice as much methane may be sequestered in natural gas hydrates as all
of the methane-equivalent fossil fuels discovered to date [6]. As energy supplies are
subject to political perturbations, hydrates become more of a viable option for countries
feeling the energy crunch. Two such countries that are counting on hydrates to contribute
to their energy needs soon are Japan and India [7, p. 913; 8, p. 344] where exorbitant
amounts of hydrates are thought to exist in the countries’ territorial waters. If these
natural gas hydrate fields can be economically farmed, then natural gas could possibly
replace many environmentally harsh fossil fuels in use today.
Closely associated with hydrate farming is CO2 sequestration or disposal. In
addition to natural gas hydrates, carbon dioxide hydrates form at conditions present on
the ocean floor. Investigations have been made to determine the feasibility of depositing
industrial CO2 gas, a greenhouse agent that is being produced at an escalating rate, on the
ocean floor in the form of CO2 hydrates [9, p. 1067]. More importantly, if this process
could in some way be coupled economically with the harvesting of natural gas hydrates,
the progression would generate a viable natural resource fuel with no apparent negative
environmental effect such as net CO2 production.
-4-
While natural gas stored in seafloor hydrates may be a potentially viable source of
fossil fuel, this natural phenomenon also suggests a conventional natural gas storage
method. By fully utilizing the close packing of hydrocarbon gas within the cavities of
gas hydrates, a theoretical volume-to-volume ratio of 180 standard cubic feet of methane
to 1 cubic foot of host water may be achieved. Recently, many groups have investigated
applying this fact. Current methods of natural gas storage (depleted reservoirs, salt dome
caverns, compressed natural gas, LNG) are either expensive or require specific geological
formations that many parts of the U.S. and other countries simply do not have. Also,
liquefied natural gas (LNG) and compressed methane are potentially dangerous sources
of explosions if a storage tank were to rupture. Natural gas hydrate storage would
effectively eliminate many of these safety and convenience concerns.
Two contrasting methods of natural gas hydrate storage have been proposed
recently. Gudmundsson patented a process in 1996 in which gas hydrates could be
filtered from a cold slurry and not only stored, but also efficiently transported from site to
site [10]. However, Gudmundsson’s method relies primarily on cold slurry filtering and
a mechanical packing system which may be cost prohibitive.
As an alternative, Zhong and Rogers proposed a method by which hydrates could
be used for peak load storage of natural gas from a process requiring no agitating,
filtering, or packing by employing surfactants to lower the surface tension of the solution
[11]. The surfactant achieved uniform spatial packaging of the gas hydrates by
adsorption on metal surfaces at the gas-water interface. Their system also induced
hydrate formation rates at a 700-fold increase over quiescent systems. While
-5-
transportation of this system would be a difficulty, the system seems economically
practical for on-site storage of natural gas.
Additionally, in 2002 Mao, et al., showed evidence of a hydrogen gas form of
hydrates [12, p. 2247]. This new discovery may have inherent implications in on-board
storage of hydrogen for fuel cells and has also been linked to deep space H2-H20
agglomerations in planets or other celestial bodies. Similarly, gas hydrates have been
investigated as a budding storage possibility for natural gas powered vehicles [13, p.
209].
When gas hydrate crystals form and agglomerate into discrete particles, any
solutes in the solution are expunged to the interstitial water of the packed hydrate
particles. This fact suggests that gas hydrates could be used to desalinate or demineralize
water sources. However, as Barduhn, et al. question the economics of such a process and
point out the dependence on the hydrating agent and the difficulty of separating
interstitial water from the hydrates [14, p. 176].
While beneficial and profitable potentials exist for gas hydrate use, many
difficulties subsist. Much work was done in the early 1930s by the oil and gas industry to
deter the formation of natural gas hydrates in production pipelines [15, p. 66]. The most
common approach was to introduce a chemical inhibitor such as methanol into the lines
to depress the equilibrium temperature for natural gas hydrates. However, this
methodology hurts the profitability of oil and gas production in deep waters offshore.
The oil and gas industry typically spends millions of dollars annually to prevent gas
hydrates from forming and plugging pipelines offshore.
-6-
To combat the problem, alternatives to thermodynamic inhibitors have been
proposed. In 2001, Huo, et al., investigated the effectiveness of using anti-agglomerates,
compounds that prevent hydrates from forming critical nucleation clusters, to prevent
pipeline plugging [16, p. 4980].
Another major problem is the effect that gas hydrates have on seafloor stability.
While gas hydrates are easily produced and are abundant in nature when the environment
is conducive, they are innately meta-stable compounds. Formation and decomposition of
seafloor hydrates may occur through shifts in temperature due to ocean currents, shifts in
geothermal gradients, or temperature changes triggered by deep-ocean drilling. Whatever
the mechanism may be, rapid decomposition of hydrates can cause enormous sub-sea
landslides on continental slopes or margins and can also trigger massive localized
releases of gas to the sea surface. Rapid dissociation of gas hydrates may also efface the
cement holding together many ocean floor sediments, turning the sediments into a low-
strength, non-cohesive mud. This type of event has serious implications to oil drilling
rigs or pipelines that may be anchored in these cemented sediments [17, p. 1791].
An increasing number of scientists have blamed a massive decomposition of
natural gas hydrates for the ending of several glacial ages and the extinction of many
species, including the disappearance of the dinosaurs and the conclusion of the last ice
age [18, p. 392; 19, pp. 357 - 358; 20, pp. 691 – 693; 21, p. 443]. In addition, Yevi and
Rogers have also referenced gas hydrates as a prospective cause for the disaster at Lake
Nyos in Africa in 1986 [13].
While irrefutable evidence is evasive at this time, there are significant indications
that gas hydrates have been in the past and may be in the future major contributors to
-7-
global climate change. Even if highly conservative estimates of the quantity of gas
hydrates are true, hydrates could potentially be the source of more greenhouse gas
(methane) than industry would produce (CO2).
Seafloor instabilities due to hydrates has prompted a massive research effort to
better understand the environment in which these compounds reside. Investigations into
hydrate interactions with sand, clays, and silt are ongoing. However, to a large extent,
mechanisms and conditions of hydrate formation on the ocean floor are still elusive.
Many questions remain as to why and where hydrates form in the depths of the
ocean. Acoustic devices and core sampling have increased knowledge substantially on
how to locate gas hydrates, but why gas hydrates form where they do and what influences
that formation is still an enigma. It has been demonstrated that certain porous media
facilitate the formation of gas hydrates, and it has also been shown that the effects of
surfactants on gas hydrate formation are also catalytic. The goal of this research is to
determine why hydrates form preferentially on surfaces and why surfactant solutions,
particularly biosurfactant solutions, seem to dictate this preference in certain cases.
Subsequently, a mechanism for the formation of hydrates in deep-sea sediment will be
proposed in the context of surfactant interaction or absence.
-8-
CHAPTER II
LITERATURE REVIEW
Hydrate Structure
Gas hydrates are a three-dimensional lattice of water, hydrogen-bonded into
regular polyhedra and stabilized by an occluded gas guest molecule that is encaged
through weak van der Waals forces. Water molecules form the vertices of the polyhedra
while line segments connecting two vertices represent hydrogen bonds. The gas hydrate
lattice has three known polymorphs designated as Structure I (sI), Structure II (sII), and
the more recently discovered Structure H (sH). The three structures differ in cubic
structure, cage diameter, and theoretical hydrate number (a ratio of water molecules
comprising the structure to the cages formed by the structure.)
Gas hydrates may be compared to ice Ih, a system of water molecules hydrogen
bonded to one another in a tetrahedral pattern forming puckered rings instead of discreet
planar sheets of ice [3, p. 25 – 27]. Unique to gas hydrates as opposed to ice, however, is
the occurrence of completely convex polyhedra that form hydrogen-bonded cages. While
ice under the same configuration would collapse, guest molecules within these cages or
within neighboring cages help establish structure rigidity and stability.
-9-
Structure I
Structure I hydrates form repetitive structures of pentagonal dodecahedra denoted
as 512 and tetrakaidecahedra denoted as 51262. This nomenclature follows the pattern
proposed by Jeffrey, imin , where mi is the number of faces of a single polyhedron and ni is
the number of edges in that face [3, p. 32]. The 12-hedron structure is the smaller of the
two geometries, is nearly spherical, and has a cage radius of 3.91Å [3, pp. 33 – 35]. The
smaller dodecahedra are comprised of 20 water molecules surrounding each guest
molecule while the larger tetrakaidecahedra are comprised of 24 water molecules
surrounding each guest molecule. The tetrakaidecahedron has an oblate structure
stemming from the orienting of two hexagons on either pole of the 14-hedron. The
average cavity radius for a tetrakaidecahedron is 4.33Å, allowing it to occlude ethane,
propane, and other non-spherically-shaped sI hydrate formers [3, pp. 36 – 37]. The sI
hydrate configuration consists of 8 guest molecules (6 large and 2 small) and 46 water
molecules arranged in a body-centered cubic unit cell. The hydrate number for Structure
I hydrates (theoretical host-to-guest ratio) is 5.75.
Structure II
Structure II gas hydrates assemble by face sharing of the pentagonal dodecahedra.
It is this face sharing that allows for the second cavity size, the hexakaidecahedron, not
present in sI or sH type hydrates. The tetrakaidecahedron is absent in sI or sH types. The
hexakaidecahedron is a 16-hedra comprised of 28 water molecules arranged into 12
pentagons and 4 hexagons (51264). The 16-hedron creates an almost spherical cage with a
radius of 4.68Å capable of supporting molecules as large as iso-butane and n-butane with
-10-
help from a smaller, stabilizing hydrate former such as methane [3, pp. 37 – 38].
Structure II hydrates fashion a diamond-centered cubic unit cell constructed of 24 guest
molecules (8 large and 16 small) and 136 hydrogen-bonded water molecules. Structure II
hydrates have a hydrate number of 5.67.
Structure H
In 1987, Ripmeester and Ratcliffe published work on a newly discovered structure
for gas hydrates [22, p. 8773 – 8776]. The new structure, designated Structure H or sH,
was known to occlude larger gas molecules than originally thought possible. This fact
occurs because larger, oblong 20-hedra cages are created within its structure. The 20-
hedron structure consists of twelve pentagonal faces along with eight hexagonal faces
(51268). Along with the 20-hedra and the pentagonal dodecahedra, there is a third cavity
size in each unit cell. Also unique to the sH type hydrate is another twelve-faced
polyhedron structure comprised of six pentagonal faces, three hexagonal faces, and three
bond-strained square faces, (435663). Due to the strain placed on the unit structure by the
435663 polyhedra, sH hydrates only occur if there is sufficient filling of the 20-hedra and
pentagonal dodecahedra to stabilize, or meta-stabilize, the clathrate. This fact has
prompted some to refer to sH type hydrate as a double hydrate, requiring a large and a
small guest molecule to form.
The sH hydrate structure is a hexagonal unit cell containing three pentagonal
dodecahedra, two of the other dodecahedra (435663), and one 20-hedron. The 435663
dodecahedra have a radius of 4.06Å while the larger 20-hedron has a radius of 5.71Å
allowing it to accommodate some cyclical and branched compounds. The sH type
-11-
hydrate has 34 water molecules per 6 guest molecules (theoretical) in each unit cell
giving a hydrate number of 5.67. A representation of each type of polyhedral cage
comprising gas hydrates is shown in Figure 2.1.
512 51262 51264 435663 51268
3.91Å 4.33Å 4.68Å 4.06Å 5.71Å
Figure 2.1. Geometry of Gas Hydrates Although each of the hydrate numbers, n, given above is below six, these values
are theoretical and rarely the case in nature. Gas hydrates can exist with only partial
filling of the hydrate cages, making them non-stoichiometric hydrates as opposed to
stoichiometric hydrate salts. Under natural conditions, however, the hydrate number may
be much larger than the theoretical value due to incomplete filling of the hydrate cages
[23, p. 4].
Gas Hydrate Sources
As stated previously, gas hydrate formation requires a concurrence of several
factors including sufficient water, sufficient gas concentration, proper temperatures, and
proper pressures. In nature, hydrates form prominently on the ocean floor and permafrost
areas where not only are temperatures and pressures adequate but water is in abundance.
-12-
Often the limiting factor is the proper gas concentration. Ocean floor and permafrost
natural gas hydrates can evolve from two major sources: thermogenic and biogenic.
Thermogenic
Thermogenic natural gas hydrates are abundant near ocean floor and permafrost
seeps. These gases are formed by catagenesis in the earth’s crust through high
temperatures and extremely high pressures, producing natural gas usually rich in ethane,
propane, and higher hydrocarbons. When fissures form in the ocean floor or near the
surface in the arctic permafrost, the gas bubbles or seeps through a large reservoir of
water where the gas may be enclathrated in gas hydrates.
Gas hydrates from thermogenic sources have both a characteristically high
amount of carbon-12 isotopes and a low ratio of methane to ethane and propane. The
Peedee Belemnite (PDB) standard is often used to distinguish between thermogenic gases
and biogenic gases and stems from the following relative reference.
( )( )
3
1213
1213
13 101 ×
−≡
PDB
Sample
CC
CC
Cδ (2.1)
Here 13C and 12C denote the different isotopes of carbon. The measurement is reported in
parts per thousand and is usually between –25% and –60% for thermogenic sources.
Equation 2.2 defines the methane-to-ethane and propane ratio.
( )32
1CC
CRMtEP +≡ (2.2)
Thermogenic gas sources typically have a ratio less than 100 [3, pp. 405 – 407].
-13-
Biogenic
Bacteria in ocean sediments or permafrost by contrast produce natural gas that is
predominantly methane. These microorganisms produce both methane and carbon
dioxide through a diagenesis process. In anoxic sediments, microorganisms are required
to reduce minerals within the sediment to sustain life. As the chemical composition of
the sediment changes with depth, the layers of microorganisms adapt to these
environments and reduce what minerals they have at their disposal. Oxidation and nitrate
reduction occur in the upper levels of sediment where dissolved oxygen and nitrate
compounds are abundant. As depth increases, sulfate reduction dominates in the region
where sulfate compounds are prominent. Finally, carbonate reduction and fermentation
becomes the method of choice as carbonate compounds increase in concentration. It is
from this region where biogenic gases are emitted into the upper layers of the sediment
where they are contacted with ample amounts of water for hydrate formation.
As a result of this diagenesis, gas sources produced by microorganisms are rich in
methane, giving RMtEP values (Eq. 2.2) of greater than 1,000. Biogenic sources also have
a considerably lower δ13C range of –55% to –85% [3, pp. 405 – 406]. This lower range
is indicative of microbes’ ability to metabolize the lighter 12C isotope rather than the 13C
isotope. As a result, methane produced by biogenic sources is high in the 12C isotope.
Biogenic sources are thought to be the dominant mode of generation of natural gas
hydrates in permafrost regions [3, p. 409].
-14-
Biosurfactants
Biosurfactants are naturally produced, surface-active compounds typically having
both hydrophilic and hydrophobic segments. Detergents are common examples of man-
made surfactants that function similarly to biosurfactants. Biosurfactants are natural
emulsifiers, solubilizers, surface tension reducers, and antimicrobial agents [24, p. 1009;
25, p. 1737]. They serve such purposes as bringing an immiscible carbon source to the
water-borne bacterial cell by solubilizing a mineral or organic compound.
Biosurfactants, acting as antibiotics, may also aid the parent microbe in competitive
exclusion where the producer is unaffected but the competition is exterminated. The
types of hydrophilic and hydrophobic groups a biosurfactant contains determines greatly
the activity and specificity of the biosurfactant. A list of the five common classifications
of biosurfactants, an example of each classification, and the accompanying parent
microbes are given in Table 2.1.
Table 2.1. Biosurfactant Classifications and Examples [26, p. 8] Classification Biosurfactant Example Parent Microbe
Hydroxylated and cross-linked fatty acids
DL-A-hydroxystearic acid Cornybacterium lepus
Polysaccharide-lipid complexes Emulsan Acinetobacter calcoaceticus
Glycolipids Rhamnolipid Pseudomonas aeruginosa
Lipoprotein-lipopeptides Surfactin Bacillus subtilis
Phospholipids DMPC Cornyebacterium insidiosum
-15-
Surfactants and biosurfactants have been recognized as good biological degraders
[24, p. 1009; 27, p. 3901]. Rhamnolipid in particular is known for its adeptness at
removing oil from sand, and Emulsan played an intricate part in the clean up of the
Exxon Valdez oil spill [28, p. 22; 29]. Surfactants, however, have only recently been
considered for use with gas hydrates. Zhong and Rogers have investigated the effect that
sodium dodecyl sulfate (SDS) has on gas hydrate formation [30]. Both Lee and
Kothapalli have recently studied the effect that biosurfactants may have on the formation
of natural gas hydrates in ocean sediments [26, pp. 78 – 81; 31, pp. 75 – 76].
Rhamnolipid
Rhamnolipid is a biosurfactant produced by the bacterial strain Pseudomonas
aeruginosa. Rhamnolipid can be mono-headed (consisting of a six-carbon sugar) or
multi-headed as well as mono-tailed (consisting of a seven-carbon alkyl) or multi-tailed.
The chemical structures of two types of rhamnolipid, one dual-headed and dual-tailed, the
other mono-headed and dual-tailed, are shown in Figure 2.2.
-16-
o
oH
CH
(CH2)6
CH3
CH2
C
o
o
o
oH
oH
oH
oH
o
o o
oHCH
(CH2)6
CH3
CH3
CH3
CH2
C
o
CH
(CH2)6
CH3
CH2
C
oHCH
(CH2)6
CH3
CH2
C
o o
o
oH
o
oH
oH
CH3
Figure 2.2. Chemical Structure of Rhamnolipid
Rhamnolipid is an anionic glycolipid that is highly surface-active as indicated by
its low critical micellar concentration (CMC) value of 18 parts per million (ppm) in water
at atmospheric conditions as a rhamnolipid mixture, or 60 ppm at atmospheric conditions
for purified mono-headed, dual-tailed rhamnolipid in water [32, p. 1995]. Rhamnolipid is
a micellar agent that orients with its hydrophilic saccharine head solvated by water and
with its hydrophobic lipid tail directed away from water, usually in a micelle (except at
acidic pH.)
-17-
Rhamnolipid’s morphology depends heavily on such factors as the pH of solution.
Since rhamnolipids are essentially carboxylic acids, they have more negatively charged
heads at higher pH values. This fact creates a morphological change from lamellae
(bilayer sheets) to vesicles (hollow bilayered, fluid-filled spheres) to micelles as pH
increases from 5.0 to 8.0 [33, p. 570 – 572].
Emulsan
Emulsan is an anionic biological emulsifier produced by the bacterial strain
Acinetobacter calcoaceticus. Emulsan is technically referred to as a biopolymer because
of its saccharine backbone that coils and twists into a tertiary structure that can emulsify
oil droplets. From this polysaccharide backbone, Emulsan has numerous lipid side-
chains giving it the classification of a polysaccharide-lipid complex. The U.S. Army has
heavily researched Emulsan in search of a biodegradable, environmentally friendly
detergent and degreaser [34]. However, due to its extraordinary size (980,000 molecular
weight) [35, p. 132] and folding abilities, Emulsan is not a micelle-forming surfactant.
The basic unit structure of the Emulsan polymer is shown in Figure 2.3.
-18-
oH COO
CH2OCO
AcNHHO o
n
oo
AcNH
o
o
o
oH AcNH
CH2OCO
Figure 2.3. Emulsan Unit Structure [34] In the above diagram, AcNH refers to a secondary amine containing an acetyl
group (COCH3) as well as being bound to the six-carbon, puckered sugar ring. The
jagged lines refer to the saturated and unsaturated lipid tails while the n denotes that the
structure is a repeating polymer chain of n subunits.
While emulsifying and degreasing properties are well known, the capabilities of
Emulsan to solubilize light n-alkane gases have not been reported. Kothapalli has
considered Emulsan for possibilities of hydrate catalysis in certain porous media [26, p.
68 – 73].
-19-
Hydrate Inhibition, Promotion, and Biosurfactants
Since the oil and gas industry first experienced gas hydrate blockage of pipelines,
the industry has been investigating ways to combat the perceived nuisance. Early on, two
methods to retard hydrate formation were employed, thermodynamic inhibition and
kinetic inhibition. Thermodynamic inhibition primarily shifted the equilibrium line for
gas-liquid water-hydrate stability while kinetic inhibition controlled the rate at which
hydrates formed, preventing detrimental plug formation in a given time frame. The
conventional method of thermodynamic inhibition, studied in depth by Hammerschmidt,
was to inject methanol which reduces the chemical potential of water [15, p. 66]. Some
thermodynamic inhibition occurs from electrolyte solutions such as saltwater solutions
[36, pp. 70 – 73]. Tohidi, et al., looked at predictive models of injecting methanol or
electrolytes to prevent pipeline blockage by hydrates. Recently Jager, et al., have shown
that the inhibitory effects of methanol and electrolytes together are greater than the sum
of their parts [37, pp. 34 – 37; 38, p. 27].
Lately a third method of hydrate inhibition, anti-agglomeration, has been
introduced. Anti-agglomerates do not affect the rate of hydrate crystallization as kinetic
inhibitors do; rather they hinder the hydrate crystals from coalescing into critical clusters
of hydrates and thus prevent precipitation. These chemicals, typically surfactants, have
an affinity for both the hydrate crystal and a liquid oil phase. Huo, et al., have
investigated many non-ionic commercial and synthesized surfactants for their anti-
agglomeration capabilities [16, pp. 4982 – 4983].
Of late, there has been a renewed interest in surfactants as a means of hydrate
promotion. Surfactants have been used to promote hydrates for natural gas storage
-20-
possibly as an alternative to LNG or compressed natural gas storage. For example,
sodium dodecyl sulfate has exhibited the ability to increase hydrate formation rate in a
non-stirred system by more than 700 fold, assist in agglomeration into a tightly packed
structure, and uptake more than 97% of the theoretical maximum uptake of methane into
hydrates [30, p. 4177; 39, pp. 5 – 9]. In addition, biosurfactants such as surfactin,
rhamnolipid, and Emulsan have been shown to promote or inhibit hydrate formation
under certain interactions with porous media [26, pp. 68 – 73; 31, pp. 75 – 76].
Porous Media
Many researchers have hypothesized about the effect that various porous media
may have on the formation, stability, and induction of gas hydrates [8, pp. 344 – 348; 26,
pp. 78 – 81; 40, pp. 237 – 239; 41, pp. 6492 – 6494; 42, pp. 977 – 980; 43, p. 3659; 44].
Recently, a connection between gas hydrate emergence and surfactants and biosurfactants
has been suggested [16, p. 4990; 26, pp. 78 – 81; 30, p. 4175; 31, pp. 98 – 100; 42, p.
973].
Kothapalli has made a connection between an increase in hydrate activity with the
presence of both porous media and biosurfactants [26, pp. 78 – 81]. Lanoil, et al., have
made the discovery of Proteobacteria, such as Psuedomonas aeruginosa, and
Actinobacteria within core samples taken from Gulf of Mexico gas hydrate mounds,
suggesting the presence of the precursors to biosurfactants used in the research for this
thesis [4, pp. 5146 – 5148].
Kothapalli also showed that natural gas hydrates have a preference to specific clay
surfaces in the presence of certain biosurfactants [26, pp. 68 – 73], and it is discussed in
-21-
following sections the preference of natural gas hydrates to the smectite clays or metal
surfaces over other surfaces.
Porous Media, Sand
Sand is comprised of a tetrahedral arrangement of silicon and oxygen in the
stoichiometric ratio 1:2 with a chemical structure SiO2. As such, the surfaces of sand
particles are negatively charged due to the dominance of oxygen’s two lone pairs of
electrons. A diagram of the tetrahedral structure of SiO2 is shown in Figure 2.4.
Sio
o
o oSi
o
o
oSi
o
oSio
o
oSi
oo
Sio
Si
o
o oSi
o
o
oSi
o
oSi
o
oSi
oo
SiSio
o
o oSi
o
o
oSi
o
oSio
o
oSi
oo
Sio
Si
o
oSi
o
o
Si
o
oSi
o
Si
oo
Si
Figure 2.4. Structure of Sand Sand’s tetrahedral pattern suggests a possibility of hydrogen bonding when in the
presence of fluids capable of such bonds. Literature suggests that while protons of water
are attracted to the surface of sand through hydrogen bonds, the bonding only occurs very
near the surface and breaks down beyond approximately three molecular layers [45, pp.
103 – 105].
Ottawa sand is a purified form of SiO2 with a narrow particle size distribution
making it amenable to research. Ottawa sand has a grain size of between 20 and 30 mesh
-22-
units. When compared to other minerals, sand has an unusually high porosity because of
its relatively large particle size, and it is noteworthy that Ginsburg, et al., state a
preference of gas hydrates for highly porous media [40, p. 237]. High-porosity, packed
media give gas hydrates more room to expand upon solidifying much like ice would.
The pH at which a metal oxide surface has a net zero charge is typically referred
to as the zero point of charge, pHZPC. At any pH value above the pHZPC, the surface will
have a net negative charge. Conversely, the surface will attain a net positive charge at
any pH value below the pHZPC. Sand has a pHZPC range of 2.9 – 3.0 meaning that, at
moderate conditions (between pH 6.0 and 8.0), sand will acquire a net negative charge
[46, p. 93]. While water will loosely solvate the surface of a negatively charged sand
particle, an anionic or poly-anionic biosurfactant will not associate with the sand surface
under these conditions. As a result, for moderate pH, no appreciable adsorbed micelles
from anionic surfactants should exist on the surface of sand.
Porous Media, Clays
Clays are typically dually defined by their size and/or by their structures. While
many technical sources refer to clay minerals as layer silicates or phyllosilicates, more
general definitions prescribe that clays consist of any inorganic material less than 2 µm in
diameter [47, p. 76]. To avoid ambiguity, clays or clay minerals will be defined
exclusively as layered silicates within this paper. Typical nomenclature refers to layered
silicates by the ratio of their tetrahedral sheets to their octahedral sheets. Hence,
pyrophyllite, a clay consisting of one aluminum octahedral sheet sandwiched between
two silicon tetrahedral sheets, is cited as a 2:1 layer silicate.
-23-
Agricultural soil typically consists of six clay groups with some exceptions:
kaolins, smectites, vermiculites, micas, chlorites, and soil clays [47, p. 83 – 88]. Only
two of these groups will be examined at length here, the kaolin and smectite groups. Of
these two groups, the kaolinite mineral will be examined from the kaolin group, and
montmorillonite and nontronite will be investigated from the smectite group.
Kaolinite
Kaolinite is a white powder commonly referred to as china clay due to its role in
creating fine china. Kaolinite is a 1:1 layered silicate with alternating silicon oxide
tetrahedral sheets and aluminum hydroxide octahedral sheets. These two layers connect
at their basal planes through hydrogen bonding. A diagram of kaolinite structure is
shown in Figure 2.5. Kaolinite in its natural state is an extremely soft mineral with a
Mohs’ hardness of approximately 1. This fact is likely attributable to its preference to
form flakes and scales upon crystallization in the monoclinic system [48, p. 43].
Kaolinite has a specific weight of 2.6. Kaolinite has an overall general structure of
Al2Si2O5(OH)4 with spacing between its basal planes of 7.2Å. Kaolinite also has a pHZPC
value of 4.7 – 5.1, resulting in an overall negative surface at moderate pH values [46, p.
93].
-24-
Si
O
Al
OH
Hydrogen Bonding Region
Figure 2.5. Kaolinite Structure [47, p. 78]
Kothapalli investigated the effect on hydrate formation of kaolinite in the
presence and absence of assorted biosurfactants [26, pp. 68 – 73]. It was shown kaolinite
wetted with 1000-ppm biosurfactant solutions, including rhamnolipid and Emulsan,
decreased nucleation time, or induction time, in all cases. The rate of formation due to
biosurfactant interaction with kaolinite increased in all instances, most notably in the
cases of rhamnolipid and Emulsan at 1000 ppm. Also, rhamnolipid and Emulsan were
shown to adsorb on the surface of kaolinite to an unquantified extent as seen by increases
in surface tension due to kaolinite contact with biosurfactant solution.
Bentonite
Bentonite clay, named after its origin of discovery in Fort Benton, Wyoming, is a
member of the smectite group. The majority of bentonite is composed of
montmorillonite clay, a 2:1 layered silicate. The mainly aluminum hydroxide octahedral
sheet in montmorillonite is sandwiched between two silicon dioxide tetrahedral sheets.
-25-
The negative charge attained by the surface of the silicon dioxide basal plane is stabilized
by exchangeable cations, most notably sodium, calcium, and magnesium [47, pp. 83 –
84]. Other metals such as iron or magnesium commonly substitute aluminum within the
octahedral sheet in montmorillonite. These substitutions cause impurities in the basic
structure. Figure 2.6 shows the structural arrangement of a sodium-exchanged
montmorillonite platelet.
+ + +
+
Si
O
Al
OH
Na+
Figure 2.6. Sodium Montmorillonite Structure [47, p. 84]
Montmorillonite crystallizes as a grayish white powder in the rhombic system.
Like kaolinite, bentonite is a very soft mineral and may attain a waxy feel [48, pp. 43 –
44]. Also like kaolinite, montmorillonite is referred to as a “plastic” clay, taking the
shape of its container when wetted [47, p. 84]. Bentonite and montmorillonite are
notorious for their water adsorptive, or swelling, properties by which they can adsorb
several times their weight in water. Montmorillonite basal plane spacing may range from
-26-
9.6Å to more than 18Å but may reach distances of tens or hundreds of Ångstroms upon
swelling. Montmorillonite, also due to its swelling properties, has many industrial uses.
The clay is typically used as cat litter because of its affinity for water and is commonly
used to adsorb harmful chemicals such as pathogenic viruses, aflatoxin, pesticides, and
herbicides [49, p. 50]. Bentonite is also a common component of drilling muds because
of its impact on the viscosity of the mud.
Montmorillonite also intercalates certain surfactants. It has been shown that both
cationic surfactant molecules [50, p. 367] and anionic surfactant molecules [26, pp. 59 –
61] adsorb on the surfaces of montmorillonite. This fact no doubt has much to do with
the swelling ability of montmorillonite and the ease of accessibility to both the negative
tetrahedral basal plane and the positive exchangeable cations along with the positive
hydroxylated edges of the montmorillonite platelets.
Also, montmorillonite has a cation exchange capability (CEC) of 80 – 150
centimoles of positive charge adsorbed per kilogram of oven-dried clay compared to
kaolinite’s CEC of 2 – 15 cmol/Kg [51]. This high CEC for montmorillonite is
attributable to its high surface area compared to kaolinite. Due to its high internal surface
area (swelling), montmorillonite can have a total surface area of as much as 800 m2/g
while kaolinite, a nonexpanding mineral, may only have a surface area of 10 to 20 m2/g
[47, p. 81 – 82].
Cha, et al., reported on the kinetic and thermodynamic promotion of hydrates due
to clay surfaces, primarily bentonite [41, p. 6494]. Also, Kothapalli showed that in the
presence of biosurfactants, the rate of hydrate formation on bentonite surfaces can change
by as much as four-fold over the rate of formation with no surfactant present.
-27-
Rhamnolipid and Emulsan exhibited an increase in rate of hydrate formation of
approximately two-fold while decreasing induction time by 39% and 58%, respectively,
on bentonite surfaces [26, p. 51, p.44].
Nontronite
A related clay surface, nontronite, has a structure similar to montmorillonite as
both are in the smectite classification. The major difference between nontronite and
montmorillonite is that iron is a larger component of the octahedral sheet compared to
montmorillonite. However, aluminum, like iron in montmorillonite, is an impurity within
nontronite. Because of the oxidized iron present in nontronite, the clay appears to have a
greenish yellow or brownish green tint. Nontronite is a slightly harder mineral than
kaolinite or montmorillonite at a Mohr’s hardness of 2 – 2.5. Nontronite has a specific
gravity of 1.7 to 1.8 [48, p. 45]. No apparent studies of gas hydrate formation and
hydrate relationship to nontronite clay existed before this investigation.
Nontronite, while technically a swelling clay, does not contain the same swelling
capacity as its montmorillonite partner as is evident by its relatively minute volume
change when hydrated.
Porous Media, Minerals
Many metal oxides, sulfates, carbonates, phosphates, and other minerals abound
in the earth’s oceans, mantle, and upper crust. Calcite and aragonite are the two most
abundant in rocks and are formed by microorganisms as polymorphs of calcium
carbonate [46, pp. 106 – 107]. Calcite crystallizes in the trigonal system while aragonite
-28-
crystallizes in the orthorhombic system [48, p. 46; 52]. The structural pattern of one of
these polymorphs, aragonite, is presented in Figure 2.7.
Figure 2.7. Aragonite Orthorhombic Structure [52]
Aragonite often forms at the Earth’s surface as a precipitate from microorganism
activity and is among the most reactive abundant minerals near the Earth’s surface [46, p.
106]. Aragonite is a white mineral with a Mohr’s hardness of 3.5. As a result of
aragonites precipitation by microorganisms, it commonly appears in shells and other
structural features of sea organisms.
Aragonite, when produced by coral or other organisms, contains an inherent
microporosity. In addition, aragonite is more soluble than its calcite partner, a fact that
often leads to a secondary porosity due to dissolution. Aragonite, being a metastable
compound, also has the ability to alter itself into the more stable calcite form during
diagenesis [53]. To date, no studies related to hydrates exist in relation to aragonite.
-29-
-29-
CHAPTER III
THEORETICAL BACKGROUND
Surfactants
Surface-active agents (surfactants) are dual character molecules that have both
hydrophilic and lipophilic tendencies. Because of this dual tendency, surfactants tend to
aggregate along interfacial boundaries [54, p. 5]. If two immiscible liquid layers are in
contact with one another, such as oil and water, then surfactant molecules will spread
along the oil-water interface with its hydrophilic group orienting to the water layer and its
lipophilic group facing the oil layer. If the boundary is a solid surface such as dirt wetted
by water, the surfactant will have much the same effect. Water solvates the hydrophilic
groups while the lipophilic groups surround the dirt particle [54, p. 140 – 143]. It is this
basic principle by which all commercial detergents, soaps, shampoos, and conditioners
function.
Surfactants are generally classified as one of four entities: anionic, cationic,
nonionic, or amphoteric (zwitterionic) [55, p. 3 – 4]. Anionic surfactants create negative
ions (anion) in aqueous solution while cationic surfactants create positive ions (cations)
that are surface active in aqueous solutions. Nonionic surfactants have no functional
groups capable of stabilizing a negative or positive charge in aqueous solution and thus
remain neutrally charged while exhibiting surface-active properties. Anionic surfactants
-30-
typically contain a carboxylate, sulfonate, or phosphate group [54, p. 74; 56; 57, p. 8]
while cationic surfactants are typically amine salts [54, p. 74; 57, p. 8; 58]. Nonionic
surfactants commonly have a water-soluble ester group which does not readily donate or
accept protons [54, p. 74; 57, p. 8; 59; 60].
Amphoteric surfactants are a mixture of the previous three classifications,
possessing attributes of each and are commonly called zwitterions in solution.
Amphoteric surfactants have functional groups proficient at stabilizing both negative and
positive charges. When these charges are balanced, the surfactant is neutral like the
nonionic surfactant. When the solution chemistry is shifted, however, these amphoteric
compounds take on either a negative or a positive charge. Amphoteric surfactants
typically carry one of each of the positively and negatively charged functional groups
such as a carboxylate group along with an amine salt [54, p. 74; 57, p. 8]. In this manner,
pH may be manipulated to determine the overall charge of the surfactant molecule [59].
The net charge attained by each surfactant dictates its activity and functionality in
certain situations. An aqueous anionic surfactant in the presence of a positive metal
surface will tend to be attracted to that surface [30, p. 4182]. Conversely, an aqueous
cationic surfactant would be repelled in the same situation. Many times it is also this
nature that dictates how easily a surfactant is stabilized or solvated in an aqueous
solution. Since water is a highly polar solvent, charged surfactants are more easily
dissolved in these situations.
-31-
Biosurfactants
Biosurfactants are a specialized class of surfactants that are produced by
microorganisms and are divided into five subcategories listed in the previous chapter [25,
p. 1732]. These subcategories may be anionic, cationic, or nonionic and serve numerous
purposes such as helping to solubilize carbon sources and to aid the bacteria in
transportation through soil media [32, p. 1993; 61, p. 230; 62, p. 60 – 61]. Industrially,
these biosurfactants are becoming more attractive because of their possible exploitation
as emulsifiers, wetting agents, foaming agents, food ingredients, and detergents to name a
few.
Some surfactants and biosurfactants are micelle-forming agents and some are not.
Micelles are highly organized structures consisting of a group of surfactant molecules
aggregating in a specific orientation [55, p. 4 – 15]. Micelles may take on assorted
shapes such as rods, bilayered sheets, vesicles, and worm-like structures [33, p. 569; 63,
p. 1360; 64, p. 3816]. The most typical example of a micelle is the spherical micelle in
which the hydrophilic heads of multiple surfactant molecules align along the surface of a
sphere with their hydrophobic tails directed inward excluding water from the interior of
the sphere. In this manner, micelles are proficient at solubilizing organic substances in an
aqueous solution in which they are typically immiscible.
It is generally understood that cationic surfactants inhibit gas hydrate formation
due to agglomeration retardation and that anionic surfactants promote gas hydrate
formation, possibly through a structuring of water and/or through an increase of gas
solubility [16, pp. 4982 – 4983; 26, pp. 68 – 73; 30, p. 4175; 39, p. 9; 65, p. 53].
-32-
Rhamnolipid
A model micelle-forming biosurfactant molecule is the rhamnolipid molecule
produced by the Pseudomonas aeruginosa bacteria. Rhamnolipid is an anionic
biosurfactant containing either one or two carboxylated sugar heads along with one or
two lipid tails. For this reason, rhamnolipid is also classified as a glycolipid.
Rhamnolipid may exist in its micellar form as a sphere, a vesicle, or a lamella (bilayered
sheet) [33, p. 570]. Rhamnolipid’s usual function is most probably to bring carbon
sources into solution where they will be accessible by the bacterial cell. Rhamnolipid
may also aid in transport of carbon sources across the cell membrane by increasing the
cell surface hydrophobicity, a process which can occur at very low biosurfactant
concentrations [66, p. 3262].
Rhamnolipid’s micelle-forming ability is notable as indicated by its relatively low
CMC value. CMC is an important solution property. The CMC is defined as the
concentration at which free surfactant molecules dissolved in solution begin to self-
associate into structure micelles. The CMC is marked by the point of sharp transition in
the surface tension versus concentration curve where the steeply declining shape abruptly
changes to a nearly flat straight line. Micelles are essential because they give surfactants
and biosurfactants their unique activities [67, p. 1229]. Micelles bring the immiscible
organic and water layers together, stabilizing one within the other.
Rhamnolipid was chosen as a test subject because of its demonstrated ability to
effectively promote gas hydrate formation and because of the identification of
Pseudomonas aeruginosa cellular material near areas containing gas hydrates in the Gulf
of Mexico [4, pp. 5146 – 5148]. The method by which rhamnolipid promotes hydrates
-33-
has been speculated as a micellar phenomenon [26, pp. 78 – 81]. Not only does a
rhamnolipid solution solubilize natural gas more efficiently, it also lowers the water
surface tension to negate somewhat the large capillary effect of water diffusing through
porous media. By easing the capillary effect, transport of gas molecules and hydrate
clusters are much easier through small pores.
Rhamnolipid has been reported to effectively increase the rate of hydrate
formation in such porous media as sand, bentonite, and kaolinite at high concentrations
[26, pp. 50 – 54]. No data currently exists for hydrate formation with rhamnolipid at
concentrations below 1000 ppm.
Emulsan
Emulsan is a non-micellar biosurfactant and was investigated for its contrast to
the rhamnolipid molecule. Emulsan is a large molecule classified as a polyanionic
biosurfactant in the subclassification polysaccharide-lipid complex. Emulsan has a long
polysaccharide backbone with numerous hydroxyl and carboxylate groups attached.
Because of its many lipid side chains, Emulsan has the ability to spread out over
an oil surface with its lipid chains directed to the organic phase and its polysaccharide
backbone directed to the aqueous phase. In a solely aqueous environment, the Emulsan
molecule bundles up into a coiled structure with the lipid chains directed inward in order
to minimize their contact with the polar water molecules [68]. Along a hydrophobic cell
surface, the Emulsan molecule can attach and extend, acting to direct complex organic
food sources into the cell.
-34-
Previous work with Emulsan showed the molecule to be proficient at directing
hydrate formation on surfaces such as kaolinite and, to a much greater extent, bentonite
[26, p. 73]. No data exists of Emulsan-directed hydrate formation at concentrations less
than 1000 ppm.
Adsorption Theory
Adsorption is defined as adhesion to a solid surface or body by a gas, solute, or
liquid in an extremely thin layer of molecules. Many times in the chemical industry,
adsorption is used to describe a catalytic process between a gas phase and a solid catalyst
such as the use of platinum and rhodium catalyst to reduce nitrogen oxide compounds
(NOx) from automobile exhausts. In soil sciences, the term adsorption commonly refers
to a process by which an organic material or an ion adheres to a soil surface. Sloan also
uses an analogy of adsorption to describe the process by which gas is enclathrated into
gas hydrates [3, pp. 208 – 211].
Adsorption Classification
Adsorption is a net result of two distinct interactions. Interactions occur between
the molecule being adsorbed (adsorbate) and the surface on which the molecule is
adsorbed (adsorbent.) Interactions can also occur between two adsorbate molecules. The
relative strength of the adsorbate-adsorbent and the adsorbate-adsorbate interactions
ultimately determine the type of adsorption that transpires. Adsorption interactions are
divided into four categories: C-type, S-type, L-type, and H-type. Examples of the four
types of adsorption are presented graphically in Figure 3.1 [69, pp. B-277 – B-278].
-35-
C - Type S - Type
H - TypeL - Type
Qua
ntity
Ads
orbe
d
Concentration
Figure 3.1. Adsorption Isotherms [69, p. B-278]
C-type adsorption, often called “constant partitioning”, is described most
effectively by a plot of adsorbate concentration versus amount of adsorbate adsorbed
called an adsorption isotherm. When these quantities are plotted for a C-type isotherm,
the result is a straight line. The shape of this isotherm tells a very important fact about C-
type adsorption. The relative affinity of adsorbate molecules for the adsorbent is constant
[69, p. B-277]. More importantly, this type of adsorption is not dependent on any type of
bonding between the adsorbate and adsorbent. C-type adsorption, like most adsorption
isotherms, is only reliable at low concentrations. This type of adsorption is usually
associated with nonpolar organic molecules.
-36-
S-type adsorption, sometimes called cooperative adsorption, exists when
adsorbate-adsorbate interactions are dominant over adsorbate-adsorbent interactions. The
S-type isotherm is an S-shaped curve which shows little or no change at very low
concentrations, rises sharply at intermittently low concentrations, and then levels off to a
constant value at higher concentrations. The slow increase at very low concentrations of
adsorbate indicates that clustering or agglomeration of adsorbate molecules is preferred
over adsorption [69, p. B-277].
The final two types of adsorption, L-type and H-type, are both types of
chemisorption and are associated with chemical bonding rather than physical attractions.
These types of isotherms are referred to as Langmuir isotherms, the H-type being an
extreme case of the L-type. These isotherms are characterized by a high degree of
adsorption at very low concentrations of adsorbate. The Langmuir isotherm and H-type
isotherm are described by the Langmuir and Freundlich equations presented below [69, p.
B-278].
+
=i
ii Kc
Kcbq
1 (3.1)
Here, the amount of adsorbate adsorbed qi is related to the equilibrium concentration of
the adsorbate in solution ci through the affinity of the adsorbate K (which determines the
slope of the isotherm) and the maximum adsorption capacity b. As stated before, when K
is very large, the L-type isotherm is typically referred to as an H-type isotherm.
L-type and H-type isotherms also inherently make five key assumptions. (1) The
surface of interest has a finite number of identical sites for adsorption, each having a
capacity for one molecule only. (2) Adsorption is a reversible process. (3) Adsorbate
-37-
molecules cannot move laterally between absorption sites. (4) The energy of adsorption
is the same for every molecule and every site independent of surface coverage. (5)
Interaction between adsorbate molecules is negligible [70].
Adsorption in Soils
Adsorption in soils is usually associated with cation or metal ion exchange.
Remediation of heavy metal contaminated soils requires an innate understanding of soil
adsorption principles where lead and mercury may be leached into the ground.
Adsorption of heavy metal ions is usually of the L-type or H-type because of their high
affinity for the negatively charged surfaces which abound in soils. Also, dissolved
organic matter (DOM) may be problematic in soil remediation typically being of the S-
type adsorption. DOM has a low affinity for soil surfaces because it typically has a low
polarity or no polarity.
Valence of cations plays a paramount role in the replaceability of a cation for
another cation. This trend referred to as the lyotropic series indicates that diavalent
cations such as calcium and magnesium are adsorbed tighter to soil surfaces than are
monovalent cations such as sodium or potassium [47, pp. 150 – 151]. In addition, cations
with larger dehydrated radii tend to be retained more proficiently than cations of the same
valence with smaller dehydrated radii.
Anionic adsorption in soils usually takes place at surfaces with a high degree of
hydroxyl sites and many times involves a loss of water by the anion being adsorbed [69,
pp. B-285 – B-287]. Adsorption of anions may be either an inner-sphere process or
outer-sphere process. Inner-sphere processes are strong surface adsorptions where water
-38-
plays no role in the adsorption (i.e. the adsorbate is chemically bound to the adsorbent.)
Outer-sphere processes involve the mediation of water by solvation of the anion and are
necessarily weaker attractions [69, pp. B-241 – B-242].
Outer-sphere processes should dominate the adsorption of anionic biosurfactant
molecules on sand and kaolinite since sand and kaolinite have a high degree of oxide
surfaces with relatively few hydroxyl surfaces. In contrast, inner-sphere processes should
dominate the adsorption of anionic biosurfactants on the surfaces of bentonite and
nontronite because of their distinct hydroxyl edge effect. Bentonite gains an added
advantage in this sense, as it will also intercalate anionic molecules into its cation-
stabilized interlayers more so than nontronite. Similarly, the surface of aragonite should
be conducive to inner-sphere adsorption with its abundant Ca+2 sites.
In addition, the possibility remains for anion repulsion or negative adsorption.
Anions with high charge densities such as Cl-, NO3-, and SO4
- are typically repulsed in
negatively charged soil surfaces. This negative adsorption can often lead to a higher
concentration of the anion in solution after being introduced to the soil. This observation
comes about by two processes. 1) The anions are expelled from the diffuse double layer
and concentrated into the bulk fluid. 2) Hydration of the soil surface removes water from
the bulk solution thus increasing the anion concentration [47, pp. 172 – 173].
Adsorption and Gas Hydrates
Gas hydrate formation is an interfacial phenomenon. Gas hydrates form most
proficiently at the source of highest gas to water ratio. Therefore, solubility of gas into
the liquid water phase is essential in increasing hydrate formation. The other key
-39-
component of hydrate formation is the statistical probability of a hydrate cage forming in
proximity to a guest molecule. Biosurfactants seem adept at increasing gas solubility.
Beyond this, they also seem proficient in some cases at directing, through adsorption, the
construction of the hydrate lattice thereby bringing the guest molecule into the right place
at the right moment. In this sense, biosurfactants seem to be most effective catalysts for
hydrate formation.
Induction Time & Nucleation Theory
Induction time is a temporal measure of the supersaturation of a gas hydrate
mixture. Induction time is the time required for gas hydrates to form a critical nucleus
cluster after achieving saturation and begin rapid hydrate precipitation. The form and
formation rate of clathrate compounds, like other crystalline compounds, are dictated by
nucleation theory. Vysniauskas and Bishnoi presented in 1983 a three-step mechanism
for the nucleation of gas hydrates: initial clustering, critical size nucleation, and
propagation and crystal growth [71, p. 1069].
The onset of gas hydrate formation can be viewed as a random ordering of
individual water molecules into a three-dimensional, hydrogen bonded system known as
the “network-cluster” model [3, pp. 68 – 74]. When approaching the freezing point,
water molecules form and break hydrogen bonded polygon structures at random. If the
concentration of gas is high enough in this dynamic system, then these hydrogen-bonded
structures will form around a gas molecule, and the gas will be encapsulated in a cell
structure. Quite intuitively, this statistical probability is greatest at the gas-water
-40-
interface, which has lead many to conclude that hydrate formation is an interfacial
process.
Vysniauskas and Bishnoi (1983) contended that the initial stage of hydrate
formation was followed by a period where these well-dispersed hydrate monomers
encountered other water molecules and other guest molecules. The hydrate structure
would then grow by the two-body interaction process until a critical size was achieved.
This critical size, known as a critical cluster, would then pass a point of irreversible
rearrangement and inherent stability.
The final step in the nucleation process is growth of the critical nucleus closely
followed by precipitation of gas hydrate “polymers.” This step is a rapid one and easily
visualized both physically and experimentally. It is also accompanied by a large
liberation of latent heat, as hydrate formation is an exothermic process. The overall
mechanism is described in the following equations.
( ) ( )yy OHMOHOHM 2122 ...↔++ − (3.2a)
( ) ( )cz OHMOHMOHM 222 .↔++ (3.2b)
( ) ( )nm OHMOHMOHM 222 .↔++ (3.2c)
In this formulation, M is the guest molecule and y, z, m, and n denote the size of any
given cluster. The c subscript denotes that at this point, the clathrate has assumed a
critical size. The ellipsis in Eq. 3.2a denotes a physical attraction while the single period
in Eq. 3.2b and 3.2c denote a bond via van der Waals forces.
In cases of some simple hydrates, an induction period is absent indicating that the
formation of a critical nucleus occurs rapidly [3, pp. 85 – 90]. However, in most other
-41-
cases, the induction period can be significant. The presence of an induction period
suggests that a rate-limiting process is also present. Since a critical nucleus is
thermodynamically stable (or metastable) and the propagation step is rapid, Equation 3.2a
must contain the rate-limiting step. This step is thermodynamically unstable and
statistically random.
Curiously, studies have shown an apparent memory effect of water upon hydrate
formation and dissociation and even upon freezing and melting [71, pp. 1064 – 1065].
Upon thawing ice or dissociating gas hydrates, the hydrogen-bonded water lattice is not
simply destroyed. Rather, the basic structure seems to be preserved while essential cage
breakage does occur to allow the gas to escape in the case of hydrates. This statement is
supported by data showing that, upon reformation with dissociated hydrate water or with
thawed water, induction time is extremely short and sometimes missing altogether.
Gas Hydrate Formation Rate (Kinetics)
Vysniauskas and Bishnoi also proposed a semi-empirical rate formulation based
on their proposed mechanism [71, pp. 1069 – 1071]. The related their mechanism to
reaction kinetics assuming that the rate of hydrate formation must be proportional to the
concentrations of water, gas, critical nuclei, and the interfacial surface area as through an
Arrhenius rate constant kr.
[ ] [ ] [ ]qnc
msr MOHOHakr 22= (3.3)
After making substitutions for the Arrhenius rate constant and substituting the
Boltzman distribution function for the critical size cluster along with some empirical
assumptions, they arrived at a rate equation for hydrate growth that is mostly theoretical.
-42-
The rate equation was a function of interfacial area as, activation energy ∆Ea, temperature
T, pressure P, the degree of subcooling ∆T, a lumped pre-exponential factor that
encompassed heat and mass transfer effects A, and two empirical parameters a and b.
Their rate equation is presented as Equation 3.4.
γPTa
RTE
Aar ba
s ⋅
∆−
∆−= expexp (3.4)
Equation 3.4 was derived for a stirred system where the gas-water interface is
renewed due to agitation. In quiescent systems the process is somewhat different but the
same parameters determine hydrate formation rate. If the interfacial surface is stagnant, a
thin film of gas hydrates forms on the surface of the liquid and blocks gas transfer to the
liquid below. This film effectively terminates further hydrate formation by reducing
mass transfer rates (A essentially approaches zero.) The only manner of hydrate
propagation in this instance is through gas diffusion through hydrate capillaries which is
an extremely slow process, sometimes taking weeks.
Past work has shown that the introduction of a surface-active agent can renew the
interfacial area of a quiescent system by 1) reducing the capillary forces, 2) increasing
mass transfer through gas dissolution, and 3) ordered packing of hydrate clusters away
from the gas-water interface [30, pp. 4177 – 4185]. Recently, others have shown that
Vysniauskas and Bishnoi’s rate equation holds approximately true for quiescent systems
under the influence of biosurfactants [26, pp. 56 – 59].
-43-
Phase Equilibria
Phase equilibria diagrams for hydrate systems give valuable information about the
conditions under which hydrates should form. Before the principles of nucleation and
induction (kinetic properties) can be fully understood, the principles of where the
thermodynamic equilibrium curves lie need to be established for reference. Two early
methods for theoretical determination of the three-phase equilibrium line for a water-gas-
hydrate system were developed, the gas gravity method and the distribution coefficient
method, and are still in frequent use today. However, the most accurate methods
employed today are statistical approaches.
Gas Gravity
The gas gravity method has been employed since 1945 to roughly estimate the
onset of hydrate formation or dissociation [3, pp. 136 – 139]. The gas gravity value is
analogous to a liquid’s specific gravity. Gas gravity (G.G.) is calculated by dividing the
molecular weight of the hydrate forming gas by the molecular weight of air as shown in
Equation 3.5. The subscript i denotes a component of the gas mixture.
Air
n
iii
MW
MWyGG
∑=.. (3.5)
The principle behind this method is that gases, irrespective of their components,
experience a shift in equilibrium on a P-T curve based on their gas gravity. Gases that
are lighter than air (G.G. < 1) are shifted up the P-T chart from the base gravity value of 1
with little or no change in the slope of the curve.
-44-
The gas gravity method has some basic generalization flaws. Namely, the
correlation was developed for hydrocarbon gases, and unacceptable errors could occur
when extrapolating data containing non-combustibles. The gas gravity method is a good
approximation for a simple initial guess but more accurate methods for determining phase
equilibria now exist.
Distribution Coefficient Method
The distribution coefficient method was conceived by Wilcox, Carson, and Katz
in 1941 and is the precursor to statistical thermodynamic methods [3, pp. 144 – 159].
Wilcox et al. hypothesized that hydrates could effectively be viewed as vapor-solid
mixtures instead of a three-phase distribution containing water. By effectively
eliminating the presence of water in their calculations, they arrived at a simple vapor-
solid distribution coefficient formulation shown in Equation 3.6.
si
ivsi x
yK = (3.6)
In Equation 3.6, yi is the mole fraction of gas component i in the water-free vapor phase
and xsi is the mole fraction of gas component i in the water-free solid.
The practicality of this formulation is that the relative ability of a gas component
to form hydrates is easily seen. Those gas components that yield a vapor-solid
distribution coefficient greater than one preferentially remain in the gas phase, and those
components with a Kvsi value less than one easily form hydrates.
Also, equilibrium temperatures and pressures can be calculated by this method
through an 18-parameter empirical formula relating the natural log of Kvsi to temperature
-45-
and pressure. With today’s increased computer calculating power, the Wilcox,Carson,
and Katz method serves as a quick and accurate estimation tool not limited to only
hydrocarbon gases.
Statistical Thermodynamics
Statistical thermodynamic determination of gas hydrate equilibrium relies heavily
on the Langmuir adsorption analogy. In this analogy, five major assumptions are made
for single component systems [3, pp. 209 – 210]:
1) The enclathration of gas molecules occurs at discrete cavities on the surface.
2) The energy of enclathration on the surface is independent of the presence of
other enclathrated molecules.
3) The maximum amount of enclathration corresponds to a monolayer, or one
molecule per site.
4) The enclathration is localized and occurs by collision of gas phase molecules
with vacant cavities.
5) The declathration rate depends only on the amount of material on the surface.
This analogy allows us to determine the fractional filling of gas hydrate cavities by
comparing it to the established Langmuir equation with slight modifications.
∑+=
JJJi
kkiki PC
PCY
1 (3.7)
In Equation 3.7, the fraction Y of i cavities filled by molecule type k can be related
to the pressure of the system P and a set of Langmuir constants. If this equation were
used for simple hydrates, Cki would be the only unknown parameter in this equation.
-46-
Overall Mechanism
Determination of an overall mechanism of gas hydrate formation in porous media
with the presence of biosurfactants is a lofty goal. However, clues as to the true nature of
the mechanism can be seen in parts of the governing equation of each interaction (simple
hydrate phase equilibrium, biosurfactant-gas interaction, biosurfactant-porous media
interaction, hydrate-porous media interaction, etc.) Based on these interactions, a
seafloor mechanism for hydrate formation can be inferred.
To say that hydrate formation is simply an interfacial phenomenon is to imply that
all other interactions between surfaces and dissolved species are negligible. This,
however, is not the case. Hydrate clustering followed by nucleation followed by crystal
growth must be a viable mechanistic pathway, but how are these steps altered by the
presence of other species? It is contended here that both biosurfactants and porous media
interact with hydrate nucleation in a synergistic fashion to promote hydrate formation,
inhibit hydrate formation, or leave hydrate formation unchanged.
Biosurfactants must by their dual nature both solubilize hydrocarbon gas and
reduce the capillary effect of water by lowering the surface tension. These effects should
act to increase the overall mass transfer rate of gas past the interfacial boundary along
with structuring the water interface very near the micelle surface and allow gas hydrates
to form in the bulk fluid more readily. In addition, the surface tension lowering effect of
the biosurfactant should improve the ability of water to be carried to the water-gas
interface through capillary effects. Capillaries of adequate size within porous media or
-47-
with hydrate structures themselves should imbibe water easily due to the lower surface
tension of the solution relative to distilled water [72, p. 589].
As a result, the typical hydrate sheet barrier of quiescent systems must be absent
allowing more hydrates to form at a faster rate. This effect may be attributable to micelle
formation but more likely is some function of particle size (whether it be a micelle or a
large molecule such as Emulsan) and solubility.
It would also be known that surfaces such as bentonite clay promote hydrate
formation while others such as kaolinite do not to an appreciable extent. Evidence has
been provided for the hydroxyl edges of bentonite or montmorillonite to be the active
agent for this increase in formation rate. If this is truly consistent, then other surfaces
with similar properties such as nontronite should have similar effects on hydrate
formation. It would also be reasonable to assume that surfaces such as sand would not
promote hydrates to any extent.
There must also be an important interaction between the biosurfactant and the
porous media. Soil adsorption of organic materials is common and expected especially in
the case of an anionic surfactant. Adsorption between the anionic surfactant is expected
to occur at the hydroxyl edges rather than at the tetrahedral oxide planes common in
many types of sediment. Therefore if adsorption were to occur, it would be most
dominant in the smectite clays and most prominent in high swelling clays such as
montmorillonite where adsorption into the interlayers seems most plausible.
Water structuring is also expected to be salient along the basal planes of
sediments, more so in sediments containing hydroxylated sites due to hydrogen bonding.
-48-
The structuring of water into hydrate-shaped cages as suggested by Cha, et al. would
lower the Gibb’s free energy needed to form the initial clusters of hydrates [41, p. 6494].
A general feasible mechanism in the case of micellar anionic surfactants is
hypothesized as the following. As concentrations increase and micelles become
dominant, the increased solubility, the decrease in the capillary effect, and the possible
increase in nucleation sites due to small micelles all serve to increase the effective
interfacial area and thereby increase hydrate formation markedly over the case of no
surfactant. In the presence of sediment, the micellar effect can be either accentuated or
depressed depending on the types of interactions between the biosurfactant and the
surfaces. Bentonite and nontronite should amplify the effect of the biosurfactants
because of their high structuring effects associated with the hydroxyl edges while Ottawa
sand and kaolinite should not change appreciably.
For the case of the non-micellar, polyanionic Emulsan, the effect should be
somewhat different. The Emulsan should solubilize natural gas to a lesser extent due to
the absence of discreet micelles. The large molecular weight and low solubility of
Emulsan should however make it a good prospect for a nucleation site. As a result, the
effect of Emulsan to increase formation rate should be more of a function of particle size
and quantity than solubility and increase of effective interfacial area. In this manner, the
Emulsan should receive much coupled effect of sediment interaction because less hydrate
formation should take place in the bulk fluid where the sediment surfaces would be
accessible. Also, the tertiary structure of Emulsan should affect the rate of hydrate
formation since water structuring near the Emulsan molecule seems plausible. When
coiled or uncoiled, the molecule would have different interactive properties.
-49-
The above mechanism relies on a number of interactions that may or may not be
differentiable or discernible. The focus of this paper, particularly the following chapters,
is a qualitative explanation of experimental results. Some points are made very clearly
by the data and others must be suggested or extrapolated. But in each case, every effort
is made to relate the data to theory-grounded molecular interactions.
-50-
-50-
CHAPTER IV
EXPERIMENTAL METHODS
Hydrate Experimental Setup
The experimental method consisted of examining the interaction of two dissimilar
biosurfactants (one which forms micelles and one which does not) with primarily five
porous media surfaces. Three of these surfaces were examined in detail while the others
were compared at points of extremity. The porous media of concern were purified
Ottawa sand, bentonite clay, kaolinite clay, nontronite clay, and aragonite (CaCO3.) The
biosurfactants evaluated were rhamnolipid, a micelle-forming surfactant from the bacteria
Pseudomonas aeruginosa, and Emulsan, a high molecular weight bioemulsifier from the
species Acinetobacter calcoaceticus.
A sample cup was constructed to simulate sediment/natural gas/water interaction
on the ocean floor and to minimize the hydrate formation time. The sample cup was
designed for maximum heat and mass transport to the sand/clay pack that it contained,
such that heat and mass transfer effects would not be rate limiting. Each sample
container consisted of a 50 ml polypropylene cup with a 2-inch long section of ½-inch
diameter clear PVC pipe epoxied in the center of the bottom of the cup. This
configuration was chosen to give a thin annular space for sediments where gas could
access the sediment from two directions. Ports were drilled into the side of the
-51-
polypropylene cup and the clear PVC to increase mass transport of gas to the porous
media. One-sixteenth inch diameter holes were drilled around the perimeter of the cup
and piping every 45 degrees. Vertically, the ports were placed ½-inch apart and
staggered ¼-inch. Five ports were also drilled into the bottom of the sample cup in the
inner PVC ring. These ports allowed for excess water drainage. A schematic of the final
sample cup is shown in Figure 4.1.
2"
2"
7/8"
1/4"
1/2"1/2"
45o
Figure 4.1. Diagram of Hydrate Sample Cup (Drawn to Scale) The reaction vessel was a 450-mL pressure cell manufactured by Parr Instrument
Company. The vessel was a Model 4762 constructed of 316 stainless steel and rated for a
-52-
maximum pressure of 2950 psi. The cell was 2.5 inches inside diameter by 5.94 inches
tall. It was fitted with two 3-wire platinum resistance temperature devices (RTDs) and an
Omega, Inc. pressure transducer calibrated from 0 – 500 psig. One RTD probe was
placed at the top of the vessel through one of the 7/8th-inch female nominal pipe thread
(FNPT) ports to measure the temperature of the bulk gas. The other RTD was placed just
at the surface of the sample through a 9/16th-inch branched fitting (illustrated in Figure
4.2) to measure the heat liberated upon hydrate formation.
Figure 4.2. Hydrate Formation Cell Photograph
RTD Probes
Relief Valve
Pressure Transducer
Parr Reaction Vessel
Natural Gas Inlet
-53-
The vessel was fitted with a pressure relief valve set to relieve at 500 psig which was also
located on the 9/16th-inch branch fitting. A diagram of the reaction vessel is shown in
Figure 4.3.
Cylinder, 450 mL,5.94" deep
Cylinder Head
Drop band with setscrew
Compression Ring
Split ring, pair, withcap screws
Gasket, PTFE
9/16" Cap screws,304 SS
Cross-sectional View
Top View
Drop band withset screw9/16" FNPT
7/8" FNPT
Figure 4.3. Diagram of Hydrate Reactor Vessel (Not to Scale)
-54-
The entire pressure vessel containing the packed media sample was submerged in a
constant temperature water bath for cooling.
Hydrate Preparation
Before preparing the porous media sample, all Ottawa sand to be used was
cleaned with ethanol to remove particulate matter. Approximately 50 ml of sand was
placed in a 150 ml beaker with enough ethanol to reach 120 ml total volume. The sand
was then sonicated with an ultrasonic horn for two minutes at 200 watts and 20 kHz
before the ethanol was drained along with any residue. This procedure was repeated and
the cleaned sand set under the hood overnight to thoroughly dry. The top of the beaker
was covered but not sealed with aluminum foil to prevent new particulate matter from
settling on the sand while still allowing the sand to dry. The sand was then placed in a
vented oven overnight at ~60oC to ensure that the sand was free of all volatile organic
material.
First, to prepare an individual sample, approximately 21 g of ethanol-cleaned
Ottawa sand was placed in the annulus of the sample cup. Second, a 1.25 g layer of the
sediment of interest was coated on top of the sand layer. These two steps were then
repeated so that four distinct layers resulted. Finally, a 25 g layer of Ottawa sand was
placed on top of the fourth layer, leaving a thin semicircular recess around the upper rim
of the sample cup. A thin 0.5 g layer of subject porous media was then laid in this recess
before proceeding to the soaking process. A schematic of the filled sample cup is shown
in Figure 4.4.
-55-
Ottawa Sand
21 g
21 g
25 g Clay or Carbonate
Cross-sectional View
1.25 g
0.5 g
Ottawa Sand
Clay or Carbonate
Top View
Figure 4.4. Filled Sample Cup The perforated sample cup was placed in a 150 ml polypropylene container. The
desired surfactant solution was prepared by weighing surfactant on a Mettler balance of
accuracy ±0.0001 g and mixing the surfactant thoroughly with an appropriate amount of
distilled water (or seawater.) The surfactant solution was then poured around the sample
cup letting the solution diffuse into the pack through the 1/16th-inch ports. The container
-56-
was capped and allowed to soak for approximately 30 minutes, after which the sediment
pack was removed from the water, placed on an absorbent cloth, covered, and allowed to
drip drain for another 30 minutes.
The drained sample was placed in the Parr reaction vessel and sealed. Air was
immediately purged from the vessel with a gas mixture of 90% methane, 6% ethane, and
4% propane before pressurizing to slightly above 320 psig. The vessel was brought to
20oC by submerging it in a 5-gallon reservoir fitted with a copper heating/cooling coil
and maintained at constant temperature with a Cole Parmer circulating bath. As needed,
the vessel pressure was adjusted to consistently reach the desired 320 psig at 20oC. The
Parr reactor containing the sample was then abruptly submerged into the constant
temperature water bath at 0.5oC.
The temperature of the hydrates, the temperature of the bulk gas, and the pressure
of the vessel were recorded at 30-second intervals. The surface tension of the
biosurfactant solution was also measured with the help of a model ST-PLUS surface
tensiometer from Tantec, Inc.
Adsorption Preparation
For each condition of hydrate formation, a series of tests were run to determine
the extent of adsorption of the particular biosurfactant on the media being tested.
Quantifying the amount of biosurfactant removed from the bulk solution by the specific
sediment substantiated this extent of adsorption. This removal is attributable to
adsorption on the surface of the porous media. However, in the case of Emulsan, some of
-57-
the biopolymer lost from solution may be due to precipitation and settling, as Emulsan is
a large molecule capable of agglomerating and settling out of solution.
To test for adsorption, a vertical packed-column configuration was employed
where biosurfactant solution contacted the porous media. The adsorption column was
constructed from a 2 feet long section of 1-inch diameter polyvinyl chloride (PVC) pipe
capped at the lower end and open at the top. The capped end of the column was tapped
and threaded to accommodate a ¼-inch polypropylene nozzle. Tygon tubing was
attached to the nozzle and clamped for control of the effluent from the column. Also, a
stainless steel wire mesh screen (greater than 30 mesh) was inserted into the base of the
column to prevent sand from fluidizing and being carried through the column. Adsorption
(or precipitation) was inferred by measuring the surface tension of the surfactant solution
before and after it passed through the column.
Each hydrate sample was contacted by approximately 250 milliliters of surfactant
solution for approximately 30 minutes before removal from the “soaking” solution and
drainage prior to hydrate formation. To maximize consistency of the results, 250
milliliters of surfactant solution at 20oC were also used for the adsorption tests.
For each adsorption test, the column was calibrated to compensate for any effects
of PVC and wire meshing on adsorption. First, surfactant solution was mixed to the
appropriate concentration, measured for surface tension, and then poured into the open
end of the vertical adsorption column. The surfactant was allowed to permeate the
porous media for approximately 30 minutes with the Tygon tubing on the effluent line
clamped. This period allowed ample time for the biosurfactant to establish adsorption
equilibrium with the PVC walls and wire meshing.
-58-
After the customary 30 minutes, 100 milliliters of the solution were drained from
the bottom of the column and discarded to eliminate any concentration gradients that
might have been created by the wire mesh. Then, three separate 20 ml samples of
surfactant were extracted from the bottom of the column and measured for surface
tension. If any variation between initial and final surface tensions of the solution
occurred at this point, it could be directly attributed to the PVC and/or wire meshing
adsorption of biosurfactant.
After completing the calibration, the column was rinsed thoroughly and dried. To
the top of the column, 70 ±0.05 g of ethanol-cleaned Ottawa sand was added along with
another 250 ml of surfactant solution. The calibration procedure was repeated, and three
20 ml samples of the effluent surfactant solution were collected and tested for disparity in
surface tension. This procedure was reiterated for concentrations of 10 parts per million
(ppm), 100 ppm, and 1000 ppm of both rhamnolipid and Emulsan solutions. Five porous
media combinations were tested. The porous media tested were 70-g of Ottawa sand and
a 67-g/3-g mixture of Ottawa sand/mineral with mineral being bentonite, kaolinite,
nontronite, or aragonite. If any residual mineral existed in the sample after removal from
the column, the sample was centrifuged for 20 minutes at 6000 rpm to remove the
sediment before surface tension measurements were taken.
Equipment
Mass Balance
The balance used for all mass weighing was an AG285 model Mettler Toledo
balance purchased from Mettler-Toledo, Inc. of Columbus, OH. For weights ranging
-59-
from 0 to 41 g, the instrument has an accuracy of ±0.01 mg with a repeatability of ±0.02
mg. For heavier weights, the balance has a maximum allowable weight of 81 g and an
accuracy of ±0.01 mg with a repeatability of ±0.05 mg.
Constant Temperature Bath
The refrigerated, constant-temperature bath used for hydrate formation was a
Model RTE-17 circulating bath purchased from Thermo NESLAB of Newington, NH.
The bath has a temperature range of –22oC to +150oC at a temperature stability of
±0.01oC. The unit has a non-CFC air-cooled refrigerating system, a circulating pump,
and a 4.5-gallon stainless steel bath basin (this basin allowed the test cell to be fully
submerged in the coolant fluid.) Distilled water was used as the circulating medium.
Equilibration Bath
The circulating bath used to establish the sample at 20oC before introduction into
the cooling bath was a Model 9105 purchased from Cole Parmer. The temperature bath
had a range of –20oC to 150oC and contained a six-liter stainless steel reservoir. The unit
had a temperature stability of ±0.05oC with a readout accuracy of ±0.5oC. The inlet and
outlet of the bath’s 15 l/min circulating pump were connected to a ¼-inch diameter
copper tubing coil submerged in a five-gallon water reservoir.
Sonicating Horn
The ultrasonic generator used for Ottawa sand cleaning was a 500-watt Model
VC501 unit manufactured by Sonics and Materials, Inc. The unit converted 60 Hz line
voltage to 20 kHz of electrical energy. The amplitude of the frequency was kept at 40%
-60-
of the maximum amplitude to prevent damage to the sonic horn. The converter was a
CV26 model attached to a standard ½-in horn. The duration of the ultrasonication was
two minutes.
Surface Tensiometer
The surface tensiometer used to measure the surface activity of the surfactant
solutions was a ST-PLUS model unit purchased from Tantec, Inc., of Schaumburg, IL.
The unit is capable of Wilhelmy Plate, Wilhelmy Plate with Detach, and DuNouy Ring
measurement methods. The Wilhelmy Plate with Detach method was employed for all
measurements. The tensiometer had a measurement range of 0 to 100 mN/m and an
accuracy of ±0.01 mN/m.
pH meter
A Model 620 pH meter was purchased from Thermo Orion of Beverly, MA to
determine pH range of surfactant solution. The instrument was connected to a Model
6165 Sure-Flow solid-state probe also purchased from Thermo Orion. The unit had a pH
range of 0.00 to 14.00 with a relative accuracy of ±0.01.
Reaction Vessel
The reaction vessel for hydrate formation was a Model 4762 stainless steel
pressure vessel purchased from Parr Instrument Company of Moline, IL. The pressure
container held 450 ml of volume and was rated for a maximum working pressure of 2950
psi at 350oC. The maximum working temperature was limited to 350oC because of the
-61-
PTFE gasket sealing the vessel. The head of the vessel had two 7/8-inch FNPT ports and
one 9/16-inch FNPT port.
Sample Container
The sample container for hydrate formation was a 50-mL polypropylene weighing
cup epoxied to a 2-inch long, ½-inch diameter section of PVC pipe. The construction and
diagram of the sample container are detailed in Figure 4.1.
RTD probes
The RTDs used in these experiments were 3-wire Platinum 100Ω models
purchased from Omega. Both probes were protected by 1/8-inch 304 stainless steel
sheaths. The Diagnostic Instrumentation and Analysis Laboratory (DIAL) at Mississippi
State University calibrated each RTD. The RTDs were calibrated for a range of 32oF to
200oF with comparisons to National Institute of Standards and Technology (NIST)
traceable equipment. The probes had a standard temperature deviation of ±0.3oC at 0oC
or ±0.8oC at 100oC.
Pressure Transducer
The pressure transducer was purchased from Omegadyne, Inc. of Sunbury, OH.
The pressure transducer was a Model PX02C1-500G5T requiring 24 – 32 Vdc excitation
with a pressure range of 0.00 to 500.00 psig. The pressure transducer was also calibrated
by DIAL with comparisons to NIST traceable equipment. The transducer repeatability
and hysteresis were both ±0.05% full-scale output (FSO) and the linearity was ±0.15%
FSO.
-62-
Linear Power Supply
A Model U24Y101 linear power supply purchased from Omega supplied the
required 28 Vdc excitation to the pressure transducer. The power supply converted a
110-V AC signal to a 24-VDC signal.
Pressure Relief Valve
The pressure relief valve was an adjustable Swagelok R3A series spring-action
valve with a red color designation. The valve was tested by a positive displacement
pump to relieve at the proper 500 psig.
Data Acquisition System
National Instruments’ FieldPoint (hardware) and LabVIEW (software) products
were used to acquire all data from the experiments. The pressure transducer was
connected to a Model FP-AI-110 analog input board while the two RTDs were connected
to a Model FP-RTD-122 3-wire RTD input board. The computer was connected to a
Model FP-1000 network interface board by a 9-pin serial cable. All three hardware
modules were jumpered to a Model FP-PS-4 24 VDC power supply supported by a 110V
outlet power cord. The data acquisition software LabVIEW was configured with the help
of National Instrument technicians. The FP-RTD-122 has a typical accuracy of ±0.15oC
and a maximum error of ±0.3oC with a resolution of ±0.016oC. The FP-AI-110 has a
resolution of ±190µV and a gain error of ±0.1% FSO.
-63-
Digital Camera
All photographs of formed hydrates were taken with a Sony CD Mavica digital
camera with 2.1 Megapixel resolution. The Sony camera wrote digital pictures to a 156
MB, 8 cm rewritable CD drive.
Materials
Rhamnolipid
The biosurfactant rhamnolipid was purchased from the Jeneil Biosurfactant
Company located in Saukville, Wisconsin. The rhamnolipid is a processed 25% active
aqueous solution, which is sterilized and practically free of all proteins. Jeneil markets
this formulated rhamnolipid solution under the product name JBR 425. Both R1
(C26H48O9) and R2 (C32H58O13) types of rhamnolipid are present in JBR 425 to an
unspecified extent.
Emulsan
Emulsan is a bioemulsifier produced by the bacteria Acinetobacter calcoaceticus.
In solid form, it is a fine yellow powder. Emulsan is comprised of a long polysaccharide
backbone with lipid side chains protruding. It has an approximate molecular weight of
980,000 and is primarily used as a degreasing agent.
Ethanol
The ethanol used to clean the Ottawa sand was purchased from Fisher Scientific,
catalog number A407P-4. For every 100 gallons of ethyl alcohol, the solvent contained
1-gal of ethyl acetate, 1-gal of methyl iso-butyl ketone, and 1-gal of aviation gasoline.
-64-
Natural Gas
The natural gas used for hydrate generation was purchased from NexAir, Inc., of
Memphis, TN. The gas has a chemical make up of methane, ethane, and propane in 90,
6, and 4 molar percentages, respectively.
Ottawa Sand
Purified silica sand, i.e. Ottawa sand, was purchased from Spectrum Chemicals of
Gardena, CA. The Ottawa sand has a chemical structure of SiO2 and a purity of 99.0 –
99.9% by weight. The Ottawa sand may also contain trace amounts of such impurities as
titanium oxide, iron oxide, and aluminum oxide. Ottawa sand has a CAS number of
14808-60-7.
Bentonite Clay
Purified sodium bentonite clay, sometimes also known as montmorillonite, was
purchased from Sigma Chemical Company. The bentonite clay has a molecular structure
of Al2O3·4SiO2·H2O and CAS number of 1302-78-9.
Kaolinite Clay
Kaolinite clay, also known as kaolin or china powder, was purchased from
Spectrum Chemical. Kaolin has a chemical structure of Al2O3·SiO2·2H2O, a CAS
number of 1332-58-7, and a face-centered cubic arrangement.
Nontronite Clay
Nontronite clay was purchased from Ward’s Natural Science of Rochester, NY.
Nontronite is very similar to bentonite clay in structure with the aluminum in the
-65-
octahedral sheet replaced primarily with iron. Nontronite clay has a principal chemical
structure of Fe2O3·4SiO2·H2O.
Aragonite
Mineral aragonite was purchased from Ward’s Natural Science. Aragonite is a
polymorph of calcite, commonly referred to as calcium carbonate. Aragonite has an
orthorhombic symmetry.
-66-
CHAPTER V
RESULTS & DISCUSSION
Scope of Results
Presented in this paper for the first time are determinations of the effect of
biosurfactants at varied concentrations on gas hydrate formation in the presence of
diverse ocean minerals. Biosurfactants interact with different minerals depending on
relative structures. Plots of biosurfactant concentration versus hydrate formation rate and
digital photographs of gas hydrate association are presented which infer adsorptive
interactions between biosurfactant molecules and mineral particles. General observations
are made here about the effect that biosurfactant/mineral interactions have on induction
time of natural gas hydrates and about the systematic ordering of gas hydrates in this
complex scheme. A mechanism is also presented here for hydrate nucleation and
formation in the presence of biosurfactants and porous media. Data are reported using
distilled water instead of seawater in most cases.
Natural Gas Hydrate Formation Rate
The experiments were conducted under constant heat transfer rates and non-
isobaric conditions. With few exceptions, a set of duplicate experiments was run for
-67-
nearly all scenarios. In cases of anomalies, triplicates or quadruplicates were run. The
experimental matrix for this investigation is shown in Table 5.1.
Table 5.1. Experimental Matrix
Rhamnolipid+ Concentration OS* OS/Bent. OS/Kaolin OS/Nont. OS/Arag.
0 ppm 3 2 2 2 2 0 ppm (w/seawater) 2 -- -- -- --
10 ppm 3 2 2 -- -- 100 ppm 2 3 2 -- -- 500 ppm 2 2 3 -- -- 1000 ppm 3 2 4 2 2
1000 ppm (w/seawater) 3 -- -- -- --
Emulsan+ Concentration OS OS/Bent. OS/Kaolin OS/Nont. OS/Arag.
10 ppm 3 2 2 -- -- 100 ppm 4 2 1 -- -- 500 ppm 3 2 -- -- -- 1000 ppm 2 3 2 -- --
* Note: OS refers to Ottawa Sand + Note: Unless otherwise noted, all runs were prepared with distilled water.
A measurable property must be chosen or defined on which comparisons can be
based to determine effects of the variables on hydrate formation. A peak formation rate
was chosen as the most accurate and repeatable outcome that could be measured and
calculated. Formation rates were inferred from the decrease in number of moles of gas
from the free gas phase upon hydrate formation. The change in number of moles was
calculated from measured temperatures and pressures recorded at 30 second intervals by
Equation 5.1.
-68-
−⋅=∆
ii
i
ff
f
TzP
TzP
RVn (5.1)
In Eq. 5.1, n is the number of moles, P is the pressure of the system, V is the volume of
the pressure vessel, z is the compressibility factor, T is the temperature of the gas, and R
is the universal gas constant. The subscripts i and f refer to initial and final conditions,
respectively. The compressibility factor z was calculated from temperature and pressure
data via the Peng-Robinson cubic equation of state. A sample Peng-Robinson calculation
algorithm is presented in Appendix B for clarity. The formation rate between successive
data points was then calculated from Equation 5.2.
tn
ttnn
rif
ifformation ∆
∆=
−
−=− (5.2)
Again, n is the number of moles of free gas and t is time. The negative sign in Equation
5.2 denotes that each mole of gas that is consumed from the free gas phase appears as a
mole of gas in the hydrate phase (1:1 molar ratio.)
The peak formation rate was defined as the maximum formation rate value
calculated between two successive data points and is indicated in Figure 5.1. The
overwhelming majority of the data, 81%, exhibited standard deviation values below 0.30
mmol/min and, in most cases (72%), below 0.20 mmol/min. Rare anomalies appeared
with standard deviations as high as 0.66 mmol/min.
-69-
1.9891
-2.0000
-1.0000
0.0000
1.0000
2.0000
3.0000
100.00 150.00 200.00 250.00 300.00
Elapsed Time
Rea
ctio
n R
ate
(mm
ol/m
in)
274.00
275.00
276.00
Tem
pera
ture
(K)
Form. Rate Temp.
Figure 5.1. Definition of Peak Formation Rate The basic shape of the rate curve in Fig. 5.1 is consistent from run to run and can
be explained from a thermodynamic standpoint. After nucleation occurs and critical
nuclei of hydrates form, gas hydrates form rapidly and liberate a significant amount of
energy to the bulk gas because of their exothermic heat of formation. Simultaneously, a
drop in pressure occurs rapidly as large amounts of gas occlude into the solid hydrate
phase from the gas phase in a short period of time. These combined effects, a rise in
temperature and a lowering of pressure, signify a rapid increase in the rate of hydrate
formation but also shift the system towards the water-hydrate-gas equilibrium line on a
pressure versus temperature plot. The swing towards equilibrium ultimately prevails and
Peak Formation Rate Value
-70-
slows hydrate formation rate (see Eq. 3.4) until the system equilibrates. The point at
which the temperature shift toward the equilibrium line (retardation of formation rate)
overcomes the rapid crystallization defines the peak formation rate of natural gas
hydrates.
A standard error was calculated to be approximately ±0.20 mmol/min for
formation rate variation between successive data points of Fig. 5.1. Therefore, the
standard deviation for peak formation rate in 72% of the data points was within the error
of the rate of formation calculation.
Effect of Biosurfactant Concentration on Formation Rate
The extent of retardation or promotion of natural gas hydrates has not been
studied as a function of biosurfactant concentration. Being anionic and polyanionic,
rhamnolipid and Emulsan expectedly promote hydrate formation in most instances, but
only at sufficient concentrations and only with certain biosurfactant/porous media
combinations.
The critical micellar concentration for micelle-forming surfactants has frequently
been viewed as a measure of a surfactant’s activity. The CMC values of surfactants have
been inferred at hydrate conditions from induction time data [26, p. 74; 30, p. 4178; 31,
pp. 70 – 74]. While these studies make the generality that anionic surfactants increase
hydrate formation rate considerably, no data currently exist for the identification of
biosurfactant concentration effects on hydrate formation in porous media.
-71-
Rhamnolipid Concentration Effects on Formation Rate
Figure 5.2 shows the effect of rhamnolipid concentration on gas hydrate
formation in the presence of Ottawa sand, an Ottawa sand/bentonite mixture, and an
Ottawa sand/kaolinite mixture. The error bars represent the standard deviation between
duplicate or triplicate runs, and in some cases, may be within the size of the data symbol.
Smoothed connecting lines have been inserted for easier visualization.
0.00
0.50
1.00
1.50
2.00
2.50
0 200 400 600 800 1000 1200
Concentration (ppm)
Peak
For
mat
ion
Rat
e (m
mol
/min
)
Figure 5.2. Effect of Rhamnolipid Concentration on Gas Hydrate Formation Rate
ο - Ottawa Sand - Ottawa Sand/Bentonite - Ottawa Sand/Kaolinite
-72-
Figure 5.2 shows that while rhamnolipid dramatically increases the rate of hydrate
formation in all porous media tested, the biosurfactant concentration at which this
increase occurs is significantly different for each surface.
Pure Ottawa sand and Ottawa sand/bentonite showed immediate effects in the
presence of rhamnolipid at concentrations of less than 100 ppm. Ottawa sand/bentonite
exhibited the most dramatic increase, which is attributable to the nature of bentonite
discussed later. Kaolinite, on the other hand, demonstrated a delay in increase of hydrate
formation rate due to rhamnolipid concentration; only showing significant increases at
concentrations between 100 – 500 ppm.
It should also be noted that, while all porous media exhibited increases in hydrate
formation rate at increased concentrations of rhamnolipid, all sediments attained the same
approximate formation rate at concentrations of 1000 ppm. This fact is supported by
tests with other types of sediment such as aragonite and nontronite. The leveling effect of
gas hydrate formation rate is presented in Figure 5.3.
Each curve in Fig. 5.2 undergoes a transition similar to the critical micellar
transition encountered when plotting surface tension versus concentration in bulk fluids.
The points at which these transitions occur in Fig. 5.2 are markedly different. While
bentonite shows this transition immediately (<100 ppm), Ottawa sand did not exhibit a
transition until the 100 ppm – 500 ppm range. Kaolinite showed the highest
concentration before exhibiting this transition (>500 ppm). This transition may be
indicative of the effective CMC value in solutions with interactions between
biosurfactant and porous media surfaces.
-73-
0.00
0.50
1.00
1.50
2.00
Ottawa Sand OS/Bentonite OS/Kaolinite OS/Nontronite OS/Aragonite
Sediment Surface
Form
atio
n R
ate
(mm
ol/m
in)
Figure 5.3. Hydrate Formation Rate at 1000 ppm Rhamnolipid The trend of gas hydrate formation rate converging to a value of ~1.55 mmol/min
at 1000 ppm of rhamnolipid suggests the presence of a rate-controlling process that
dominates at high concentrations. This process assuredly relates to the attainment of a
micellar concentration of rhamnolipid, the adsorption of rhamnolipid on sediment
surfaces, or most likely a combination of both mechanisms.
Emulsan Concentration Effects on Formation Rate
In the presence of porous media, Emulsan presents a much different effect on gas
hydrate formation as a function of concentration. Emulsan concentration and hydrate
-74-
formation rate seem to be related in a nearly linear fashion in the presence of Ottawa
sand, bentonite, and kaolinite. Figure 5.4 displays these apparent trends on sediment
surfaces.
0.00
1.00
2.00
3.00
0 200 400 600 800 1000 1200
Concentration (ppm)
Peak
For
mat
ion
Rat
e (m
mol
/min
)
Figure 5.4. Effect of Emulsan Concentration on Gas Hydrate Formation Rate Figure 5.4 shows that Ottawa sand and Ottawa sand/Bentonite systems exhibit
approximately the same general relationship, a linear increase of hydrate formation with
increasing Emulsan concentration. Note that the slope of both lines is approximately the
same. Since Emulsan is a non-micellar surfactant, this phenomenon may be explained by
Bentonite
Ottawa Sand
Kaolinite
-75-
the increase of nucleating particles (i.e. Emulsan particles) as the concentration increases.
Bentonite again exhibits a higher rate of formation at each point relative to the other
sediment surfaces. This trend will be discussed further in sections to follow.
Unlike bentonite and Ottawa sand, kaolinite causes no apparent change in hydrate
formation rate upon subsequent addition of Emulsan. These data suggest that in some
fashion kaolinite is deactivating the Emulsan or negating its effect on the hydrate kinetics
and thermodynamics. Furthermore, to accomplish this, kaolinite must effectively
eliminate the increasing number of nucleating sites that Emulsan would present. It is
possible that kaolinite is causing a conformational change of Emulsan whereby the
Emulsan molecule would not resemble the typical size or shape of a hydrate-nucleating
particle.
Several possibilities for this exist. (1) One method by which this could occur
would be Emulsan spreading on the surface of kaolinite that is known to occur on the
surface of oil-water emulsifications [68]. If this spreading were to occur with the
lipophilic groups directed towards kaolinite, Emulsan could not effectively transport gas
to the solution. (2) Emulsan-kaolinite ion exchange is preventing the molecule from
unfurling on the water-gas interface and collecting gas essential for nucleation. (3)
Emulsan-kaolinite ion exchange is preventing precipitation of Emulsan such that small
nucleating particles are no longer present. However, the last two explanations seem less
likely considering kaolinite has a high likelihood of anion repulsion to the polyanionic
Emulsan molecule.
-76-
Effect of Porous Media on Formation Rate
Porous media has been documented as having a significant surface effect on the
rate of gas hydrate formation and dissociation in the absence of any surfactant or
biosurfactant. Ginsburg, et al., have presented the preference of gas hydrates toward
areas of high porosity [40, p. 237]. Uchida, et al., also noted that the dissociation
temperature of methane hydrates varied in an inversely proportional fashion to pore
diameter in porous glass of pore diameter between 100 and 500Å [43, p. 3659]. Cha, et
al., proved that sodium montmorillonite promoted hydrate formation due to a “possible
surface ordering” effect in which the hydroxide edges of montmorillonite act as one side
of the hydrate lattice [41, p. 6492].
Furthermore, peak formation rate data of this study also show a trend toward
specific surfaces under the influence and absence of biosurfactants. Figure 5.5 shows the
peak formation rate of natural gas hydrates in distilled water and on various mineral
surfaces.
-77-
0.540.45
0.75
0.90
0.40
0.00
0.20
0.40
0.60
0.80
1.00
1.20
1.40
1
Sediment Surface
Form
atio
n R
ate
(mm
ol/m
in)
Ottawa Sand Bentonite Kaolinite Nontronite Aragonite
Note: No Biosurfactant Present Figure 5.5. Effect of Sediment on Peak Formation Rate in Distilled Water Figure 5.5 shows that Ottawa sand, kaolinite, and nontronite all have base values
that approach 0.45 mmol/min. A near doubling of formation rate occured when bentonite
is present as predicted by Cha, et al. Interestingly aragonite induced an increase in
hydrate formation rate to a value of 0.75 mmol/min.
Cha, et al., hypothesized that the hydroxyl edges of the bentonite clay were
forming hydrogen-bonded links between the gas hydrate lattice, incorporating itself into
the hydrate structure [41, p. 6494]. If this hypothesis were completely true, then it would
be expected to see a similar effect with nontronite which has a similar layer structure to
-78-
bentonite. This was not the case. As a matter of fact, there appeared to be a depression
in formation rate between nontronite clay and the control surface, Ottawa sand.
Alternatively, the increase in hydrate formation rate caused by bentonite is
apparently due to the intercalation of water molecules and structuring in the water phase
between the basal planes. Kaolinite has no noticeable intercalation of water due to
strong, well-structured hydrogen bonding between the basal planes of its platelets [47, p.
83]. Nontronite also has no appreciable intercalation of water as evidenced by its relative
lack of swelling in water media. However, bentonite intercalates not only water
molecules but also surfactant molecules quite easily [50, p. 367]. These data suggest that
the key to hydrate promotion by clay surfaces may not be in surface interactions, but
rather in interlayer interactions.
Aragonite presents a different type of anomaly. Aragonite has no layers to
intercalate with water, yet it induced a significant increase in natural gas hydrate
formation rate with distilled water. One possible explanation is that the CaCO3 structure
organizes the water layer very near the water-gas interface. Aragonite is a microporous
structure with ample surface area to structure water and promote hydrate growth.
Support for this explanation is presented in depth in a following section.
Adsorption of Biosurfactants on Porous Media
Quantitative adsorption tests were conducted to determine the relative extent of
biosurfactant adsorption by each type of sediment surface. From changes in surface
tension of entering and exiting water solutions, the adsorptivity of each surfactant was
measured. The preference of each surfactant for a particular surface was then inferred by
-79-
determining surfactant concentration from the surface tension versus concentration
calibration curve (See Appendix A for curves, see Chapter IV for procedure.) The
surface tension differences of these tests are shown below in Table 5.2.
Table 5.2. Biosurfactant Selective Adsorption Test Rhamnolipid on Ottawa Sand Emulsan on Ottawa Sand Concentration Standard Surf. Tension ∆(S.T.) Standard Surf. Tension ∆(S.T.)
(ppm) (mN/m) (mN/m) (mN/m) (mN/m) (mN/m) (mN/m)10 4.7 2.4 -2.3 -3.2 -2 1.2
100 4.5 6.4 1.9 -0.7 -0.4 0.3 1000 -0.1 -0.2 -0.1 -0.8 -0.6 0.2
Rhamnolipid on Bentonite Emulsan on Bentonite
10 4.7 13.3 8.6 -3.2 10 13.2 100 4.5 21.3 16.8 -0.7 10.4 11.1
1000 -0.1 9.7 9.8 -0.8 4.7 5.5 Rhamnolipid on Kaolinite Emulsan on Kaolinite
10 4.7 0.7 -4 -3.2 -3.7 -0.5 100 4.5 10.3 5.8 -0.7 0 0.7
1000 -0.1 1.3 1.4 -0.8 0.5 1.3
Table 5.2 shows that, for the case of rhamnolipid, there was notable adsorption by
the blank trial at lower concentrations (<100 ppm). This trend was expected, as an
anionic surfactant is susceptible to being adsorbed onto metal surfaces such as the wire
mesh used to keep sediment from being eluted through the column.
For similar reasons, the reverse trend for Emulsan is curious. The fact that no
negative adsorption is perceived at these concentrations may be attributable to the
valence structure of Emulsan. The polyanionic biosurfactant may be repulsed notably by
the PVC walls as the walls are subsequently hydrated. Repulsion followed by hydration
of the PVC walls would both concentrate Emulsan in the bulk and concentrate water
-80-
away from the bulk. These combined effects would give Emulsan a higher concentration
after being passed through the column than before and would result in a decrease in
surface tension instead of the expected rise. This observation is present in other porous
media tests also.
In the presence of rhamnolipid, bentonite clay seemed to have the largest effect on
adsorption. This fact was predicted by the presence of the hydroxyl sites along the edges
of a bentonite platelet that easily serve to adhere an anionic surfactant. Also the
intercalation of rhamnolipid into bentonite interlayers surely plays a significant role.
While each surface shows some adsorption at 100-ppm concentrations, only bentonite
shows adsorption at 10-ppm concentrations. This fact is very telling, suggesting that a
weak adsorption is occurring at 100 ppm which is absent at 10 ppm for all surfaces
except bentonite. This absence can be accounted for by the lack of micelles at 10-ppm
concentrations. In other words, in the presence of sand or sand and kaolinite,
rhamnolipid is adsorbed in clusters of micelles, not as individual molecules.
The same seems to be true at 1000-ppm concentration but is easily explained. At
1000 ppm, a great amount of adsorption would have to take place to noticeably change
the surface tension. A 1000-ppm concentration is well into the horizontal portion of the
surface tension curve. This explanation is also supported by a similar trend in the
Emulsan test. This explanation attributes to the large adsorptive capacity of bentonite
since a large amount of rhamnolipid must be adsorbed to noticeably change surface
tension in this region.
Emulsan shows little or no adsorption on sand or a sand/kaolinite mixture at any
concentration. Since no micelles form with Emulsan, there is no micelle clustering at the
-81-
surface of the sediment as was suggested in the previous explanation. However, as
before, bentonite showed a relatively high affinity for the Emulsan molecule at all
concentrations. Presumably, this fact is caused by the attraction of the polyanionic
molecules to the net positive hydroxyl edges of the bentonite platelet and possibly also in
the interlayers of bentonite.
Adsorption and Biosurfactant Concentration Related to Formation
Four adsorption isotherms commonly appear in adsorption or chemisorption
kinetics: the L-type isotherm, the S-type isotherm, the C-type isotherm, and the H-type
isotherm [69, p. B-277]. The shape of each curve, discussed in Chapter III, indicates the
type and extent of adsorption or chemisorption by an ion or molecule to a solid surface.
The shape of each biosurfactant concentration versus gas hydrate formation rate
plot has a very distinctive curve which is porous media dependent. Sloan has also
proposed that gas enclathration is analogous to adsorption and desorption [3, pp. 208 –
211]. The current data suggest that the shape of the concentration versus hydrate
formation curve is not accidental, but likely dictated by the adsorptive characteristics of
each mineral-biosurfactant interaction. Thus, the affinity of a biosurfactant molecule can
be qualitatively deduced from the curvature of these formation plots. In the case of
rhamnolipid, a necessary assumption is that at higher concentrations of rhamnolipid,
adsorption and desorption are in equilibrium and free micellar shapes dictate the
formation rate regardless of porous media present.
Ottawa sand in the presence of rhamnolipid had a relatively intermediate slope at
lower concentrations (<300 ppm) and effectively leveled off to a stable peak formation
-82-
rate value of 1.64 mmol/min. Figure 5.6 shows the change in peak hydrate formation rate
due to rhamnolipid concentration in an Ottawa sand pack. Figure 5.6 and Figures 5.7 and
5.8 to follow were fitted with cubic splines to better visualize the overall trend in gas
hydrate formation.
0.00
0.50
1.00
1.50
2.00
0.00 200.00 400.00 600.00 800.00 1000.00 1200.00
Concentration (ppm)
Peak
For
mat
ion
Rat
e (m
mol
/min
)
Figure 5.6. Rhamnolipid Concentration Vs Peak Formation Rate in Ottawa Sand The plot of Fig. 5.6 is indicative of a typical L-type (Langmuir) plot, which rises quickly
but levels off to a constant quantity. The L-type curve for Ottawa sand and rhamnolipid
suggests that adsorbate-adsorbent interactions are relatively high and may be indicative
of chemisorption. The means by which this occurs is unclear, however, since the surface
of Ottawa sand should be a net negative surface and rhamnolipid is an anionic surfactant.
The chemisorption may be an interaction between micelles adsorbed on the surface of
-83-
sand (admicelles). This fact would explain the lack of appreciable change in peak
formation rate in the 10-ppm concentration range before micelles form.
In the presence of bentonite, the rhamnolipid concentration versus peak formation
rate curve takes on a similar shape with a much steeper initial slope. This initial slope is
followed by a maximum and then a slight decline back to a micelle-dictated value of 1.50
mmol/min. This curve is presented in Figure 5.7.
0.00
1.00
2.00
3.00
0.00 200.00 400.00 600.00 800.00 1000.00 1200.00
Concentration (ppm)
Peak
For
mat
ion
Rat
e (m
mol
/min
)
Figure 5.7. Rhamnolipid Concentration Vs Peak Formation Rate in Bentonite Clay The steepness of the rise in the lower concentration range for bentonite suggests a much
stronger affinity of bentonite for the rhamnolipid molecule than exhibited by Ottawa
sand. The rise is so extreme that it borders on an H-type isotherm, indicating very strong
adsorbate-adsorbent interaction.
-84-
The presence of a peak value and decline upon subsequent addition of
rhamnolipid is a curious one. This peak may be brought about by a filling of the
interlayer of bentonite due to intercalation of rhamnolipid. Once this interlayer is filled
by admicelles, the interlayer is deactivated, shifting the formation back to a free-micelle
directed formation rate. This explanation is under the assumption that adsorption of
rhamnolipid is notable in the interlayers in addition to adsorption along the hydroxylated
edges of the bentonite platelets.
Kaolinite in the presence of rhamnolipid gives a very distinctive S-shaped
adsorption curve. The S-shaped adsorption curve results when adsorbate-adsorbate
interactions are stronger than the adsorbate-adsorbent interactions causing clustering of
adsorbate molecules near the surface. This clustering of adsorbate molecules for the case
of rhamnolipid is micelle formation. The relative absence of adsorbate-adsorbent
interaction in the case of kaolinite may be the result of anion repulsion. The S-curve for
kaolinite is presented in Figure 5.8.
-85-
Effect of Rhamnolipid on Kaolinite
0.00
0.50
1.00
1.50
2.00
0 200 400 600 800 1000 1200
Concentration (ppm)
Peak
For
mat
ion
Rat
e (m
mol
/min
)
Figure 5.8. Rhamnolipid Concentration Vs Peak Formation Rate in Kaolinite Clay Through weak adsorbate-adsorbent interactions, kaolinite may deactivate a
number of the rhamnolipid molecules not allowing them to form micelles or admicelles.
These interactions could result in a significant increase in the CMC value of rhamnolipid
and could be responsible for the slow formation rates at low rhamnolipid concentrations
with respect to Ottawa sand or bentonite.
Emulsan in the presence of porous media presents a very different curve of
concentration versus peak formation rate (see Fig. 5.4.) With each porous media tested,
this curve is approximately linear, indicative of C-type adsorption. Equations 5.3, 5.4,
and 5.5 show the best fit curves for peak hydrate formation rate versus Emulsan
concentration in the presence of bentonite, Ottawa sand, and kaolinite, respectively.
-86-
9893.00011.0 +⋅= EMPF Cr (5.3)
6334.00008.0 +⋅= EMPF Cr (5.4)
43.0=PFr (5.5)
In the above equations, rPF is the peak hydrate formation rate measured in mmol/min, and
CEM is the concentration of Emulsan measured in ppm.
The C-type adsorption is characterized by a constant relative affinity of adsorbate
to adsorbent. If this is the case, then bentonite clay shows the highest affinity for
Emulsan of any media while kaolinite clay shows no affinity at all. Curiously, the slope
of the C-type straight line for the Ottawa sand system and the Ottawa sand/bentonite
system are nearly the same (see Figure 5.4.) This fact suggests that the relative affinity of
Emulsan to Ottawa sand and bentonite is approximately the same. The shift in intercept
of these two lines can be explained by the additional structuring effect that bentonite
possesses over Ottawa sand as discussed previously.
The C-type adsorption curve for kaolinite in the presence of Emulsan has a slope
of zero. It is, however, unlikely that Emulsan has no affinity for kaolinite. A more
plausible explanation would be that the lipophilic groups of the Emulsan are adhering to
the surface of the kaolinite clay, much like a commercial surfactant would adhere to an
organic particle. The adhesion of the lipophilic groups to the kaolinite would deactive
those moieties from solubilizing gas but more importantly would destroy the tertiary
structure of Emulsan. The unfurling of the Emulsan molecule could prohibit it from
providing nucleation sites for the gas hydrates to originate.
-87-
Induction Time
Induction time is defined for the subject experiments as the difference between
the onset of hydrate crystallization and the time at which the gas hydrate equilibrium line
is crossed (point of supersaturation). Induction time gives a simple understanding of the
time required to accumulate a critical nucleus of hydrate crystals upon supersaturation
[73]. Studies recently have hinted at a possible correlation between induction time and
the critical micellar concentration of rhamnolipid [26, p. 74; 30, p. 4178; 42, p. 977]. The
length of induction time is shown below in a representative temporal plot of pressure
versus temperature noting the amount of supersaturation.
240.00
250.00
260.00
270.00
280.00
290.00
300.00
310.00
320.00
270.00 275.00 280.00 285.00 290.00 295.00
Temperature (K)
Pres
sure
(PSI
G)
Run #100 Formation Equil. Run #100 Decomposition
Ottawa SandDistilled Water/Rhamno (1000 ppm)Moisture (sat'd)
Ti
Figure 5.9. Induction Time in Gas Hydrate Growth
Induction Time
-88-
Each run was given a maximum of 48 hrs to begin forming hydrates, and
induction time was calculated for each case in which hydrates formed. A select few
experiments had induction times that could not be determined due to slow hydrate
formation. Eleven cases did not form hydrates to any appreciable extent or had
indeterminate induction times.
For cases where hydrates formed, induction times ranged from less than one hour
to as long as 34 hours. To demonstrate that hydrates would eventually form if given
ample time, one experiment was left running for longer than the allotted 48 hour
maximum and had an induction time of over 75 hours. Table 5.3 below shows the
average induction time for all runs that formed hydrates and the standard deviation. In
Table 5.3, OS denotes Ottawa sand, BE denotes bentonite clay, KA denotes kaolinite
clay, NO denotes nontronite clay, and AR denotes aragonite.
-89-
Table 5.3. Induction Time
Rhamnolipid
Conc. (ppm)
Ti, OS (hrs)
Stand. Dev.
Ti, OS/BE (hrs)
Stand. Dev.
Ti, OS/KA (hrs)
Stand. Dev.
0 7.77 5.47 2.32 1.93 3.73 2.19 10 6.67 -- 6.43 2.20 3.90 2.20
100 1.50 0.42 2.31 1.45 3.23 2.03 500 40.63 49.13 1.63 0.68 4.94 2.59
1000 9.04 5.70 14.77 15.59 1.94 0.52
Emulsan
Conc. (ppm)
Ti, OS (hrs)
Stand. Dev.
Ti, OS/BE (hrs)
Stand. Dev.
Ti, OS/KA (hrs)
Stand. Dev.
0 7.77 5.47 2.32 1.93 3.73 2.19 10 6.59 7.91 3.60 3.02 32.23 --
100 1.51 -- 2.23 1.56 10.88 -- 500 10.80 4.03 3.00 1.09 -- --
1000 14.84 11.68 5.17 3.99 3.48 0.71
Rhamnolipid Rhamno/Seawater
Conc. (ppm)
Ti, OS/NO (hrs)
Stand. Dev.
Ti, OS/AR (hrs)
Stand. Dev.
Ti, OS (hrs)
Stand. Dev.
0 9.19 -- 0.60 0.24 5.63 1.26 1000 6.38 5.32 17.32 23.50 3.92 1.24
Table 5.3 shows that there appears to be no correlation between induction time
and biosurfactant concentration. The data presented seem to be erratic and irreproducible
as demonstrated by the high standard deviation values, in some cases exceeding the
average induction time values. This fact may possibly be explained by the difficulty in
reproducing accurately the quantity of nucleating sites when porous media is present.
Other studies that have suggested a correlation between biosurfactant concentration and
induction time have been in the absence of porous media.
-90-
Heat and Gas Transfer Effects on Formation Rate
Other researchers have examined the role of heat and mass transfer rates on gas
hydrate formation [44; 71, pp. 1069 – 1071; 74, pp. 301 – 302; 75, p. 465; 76]. While
mass transfer affects the rate at which gas molecules are contacted with prospective
hydrate cages, heat transfer dictates the rate at which the heat of formation is removed,
and thus, sets the location of the operating point relative to the equilibrium curve. With
these facts in mind, the experiment was conducted to minimize deleterious mass transfer
and heat transfer effects.
Figure 5.10 compares experimental runs limited by heat and mass transfer to
experimental runs where heat and mass transfer limitations are negligible. For
comparison purposes, the data have been normalized by dividing each data set by the
fastest peak formation rate within each set. The data represented in Fig. 5.10 were
obtained with 1000 ppm rhamnolipid-distilled water solution on a Ottawa sand/bentonite
pack.
-91-
0
0.2
0.4
0.6
0.8
1
0 200 400 600 800 1000 1200
Concentration (ppm)
Peak
For
mat
ion
Rat
e (n
orm
aliz
ed)
Not Heat & Mass Transfer Limited Heat & Mass Transfer Limited
Figure 5.10. Effect of Heat and Mass Transfer Limitation Figure 5.10 shows that under heat and mass transfer limited conditions, an inverse
correlation exists between concentration of rhamnolipid and peak formation rate. In
other words, under the limitations of heat and mass transfer, rhamnolipid is a hindrance in
the formation rate of gas hydrates.
Mass transfer limitations resulted in the experiments when insufficient gas ports
were available for gas access. Possibly, rhamnolipid molecules at the water-gas interface
promoted hydrates to block those gas access ports, thereby providing a barrier rather than
a means of gas transport when interfacial area is limited. Another explanation could be
that the presence of rhamnolipid is altering the bulk heat capacity of the solution such,
that under heat transfer limited conditions, the heat of formation cannot be removed
-92-
effectively. In addition, the Teflon container used previously, as opposed to the thinner
polypropylene sample container, allowed for less heat transfer into and out of the sample.
Effect of Electrolytes on Formation Rate
Electrolyte solutions have been extensively documented to inhibit gas hydrate
formation [36, pp. 70 – 73; 38, pp. 22 – 27; 77, p. 1719 – 1721; 78]. This fact has been
theorized to be attributable to the change in colligative properties of the liquid phase
whereby freezing point may be depressed. The inhibition may also have to do with the
energy required to expunge the electrolyte particles into the interstitial water and out of
the gas hydrate lattice.
A series of experiments were undertaken to determine the approximate effect of
Gulf of Mexico seawater on the rate of hydrate formation in the presence and absence of
biosurfactant. The formation rate in seawater was compared to distilled water in an
Ottawa sand pack and to a 1000 ppm distilled water-rhamnolipid solution in an Ottawa
sand pack. The data are presented in Table 5.4.
Table 5.4. Effect of Electrolytes on Gas Hydrate Formation
Peak Formation Rate
(mmol/min) † STDEVPeak Formation Rate
(mmol/min) ‡ STDEV DI Water 0.54 0.04 1.64 0.32 Seawater 0.39 0.04 1.47 0.40 † - No surfactant present ‡ - 1000-ppm rhamnolipid present
-93-
As expected, it appears that the peak formation rate is depressed by seawater in
the presence and absence of biosurfactant, but the value differences are very near the
limits of experimental error since the saltwater concentration is low.
Gas Hydrate in Porous Media, Preference Trends
In porous media, gas hydrates have a preference for high porosity [40, p. 237].
This fact is intuitive because gas hydrates, like ice, expand upon formation. Therefore, it
is expected that gas hydrates would form in regions of highest gas-water interfacial area
with the most room to expand. This observation is witnessed as gas hydrates routinely
form around the mouth of the sample cup and around the gas ports into the media pack.
Beyond this intuitive observation, however, is the preference of gas hydrates to
agglomerate on certain surfaces in preference to other surfaces when given the choice.
For instance, in the presence of Ottawa sand as the only porous media, hydrates choose to
cluster about the stainless steel RTD probe that just contacts the surface of the sand. Not
only do gas hydrates prefer the stainless steel to silica, but also gas hydrates often bridge
from the sample cup to the stainless steel walls of the reaction pressure vessel. This
phenomenon is shown in Figure 5.11.
-94-
Figure 5.11. Preference of Gas Hydrates to Stainless Steel Over Silica (OS) This preference of gas hydrates to stainless steel was present in all cases where
Ottawa sand or kaolinite was the principle surface of interest. Only in the cases of
bentonite, nontronite, and aragonite did the preference shift.
Quite noticeably gas hydrates prefer, given the opportunity, to crystallize on the
surface of the smectites over the silica or stainless steel. In all cases of bentonite and
nontronite (with rhamnolipid, Emulsan, or neither present), massive hydrates formed
around the mouth of the sample cup around the semi-circular region containing the
smectite. Figure 5.12 clearly demonstrates this fact.
Vacancy created by RTD probe
OS, Rhamno. (1000 ppm)
OS, Emulsan (1000 ppm)
Hydrate bridging to SS vessel wall
-95-
Figure 5.12. Preference of Gas Hydrates to Smectites This preference possibly occurs due to structuring effects of the smectite clays on
the water phase versus the other surfaces. It has been proposed that the intercalation of
water and possibly surfactants into the smectite interlayer causes an ordered system and
dually acts as a nucleation site for subsequent hydrate formation [41, p. 6494].
Aragonite was mentioned previously to promote gas hydrate formation in the
presence of distilled water. Under this condition, gas hydrates formed prominently on the
surface of the aragonite as well as the stainless steel RTD probe. However, when
Bentonite
Nontronite
Ottawa Sand
Ottawa Sand
-96-
rhamnolipid was introduced, the preference shifted to the shielded RTD probe. This
observation suggests that aragonite effectively organizes water and promotes gas hydrates
as long as distilled water is the only medium. But when an anionic surfactant such as
rhamnolipid is introduced, the surfactant is attracted to the metal surface and promotes
gas hydrates away from the aragonite surface. Figure 5.13 clearly shows this
observation.
Figure 5.13. Preference of Gas Hydrates to Aragonite with No Surfactant Present
Gas Hydrate Packaging, Biosurfactant Ordering
Gas hydrates are known to assume such packing arrangements in ocean sediments
as massive, nodular, dispersed, dendritic, needle-like, and stratified [23, pp. 88 – 102].
No Surfactant Present 1000 ppm Rhamnolipid Present
Aragonite Aragonite
-97-
For this investigation, four types of hydrate packing arrangements dominated: massive,
nodular, dendritic, and needle-like. Dendritic and needle-like hydrates were the most
commonly observed forms of hydrates in the absence of biosurfactants or when
biosurfactants were at low (<l00 ppm) concentrations. However, when concentrations of
biosurfactant was greater than or equal to 100 ppm, hydrates took on a general
appearance of massive, rounded hydrates with intermittent cases of nodular hydrates.
These general hydrate conformations are presented in Figure 5.14.
Figure 5.14. Gas Hydrate Packing Arrangements
Nodular Massive
Dendritic Needle-Like
-98-
Makogon has attributed the presence of needle-like hydrates to hydrate crystal
growth from water in the vapor phase attaching to an already growing hydrate nucleus
[23, pp. 88 – 89]. Yet the shift from a needle-like morphology to a massive, amorphous
morphology upon increase in biosurfactant concentration suggests that surface tension
has a fundamental role. If needle-like hydrates are being grown from vapor phase water,
then a lowering of surface tension and the capillary effect may be dictating the close-knit
packing arrangement observed when biosurfactant is present at appreciable
concentrations. The surface activity at higher concentrations is dictating the crystal
growth and allowing for a higher ordered structure. This fact is supported by the
apparent transition from primarily needle-like to primarily dendritic to primarily massive
hydrates upon increase in biosurfactant concentration.
In fact, it may be reasoned that the case of dendritic hydrates as an intermediary
has significance. At 10 ppm concentrations, the solution does not have a high enough
concentration to promote hydrates and crystal growth is initiated from the vapor phase.
However, as gas hydrates form, water is removed from the solution leaving behind the
biosurfactant in the interstitial water. As some point, this effect could concentrate the
interstitial water to a point beyond where surface tension plays a role. At this point,
hydrates would grow to a more uniform, rounded massive structure. This explanation is
supported by Fig. 5.14 where both massive structures and dendritic crystals can be seen.
Also notably, aragonite with distilled water exhibits dendritic hydrates as
compared to needle-like hydrates (See Fig. 5.13.) This observation supports the
explanation that aragonite inherently structures the water near the water-gas interface
such that a more ordered system appears rather than a random needle-like structure.
-99-
Dispersed Sediment in Massive Hydrates
One phenomenon that is significant and should not be overlooked is the
dispersion of fine sediment particles within the gas hydrate matrix. The most noticeable
case of this event was with nontronite clay. When hydrates form massive collections on
the surface of the nontronite semi-circle, the massive hydrate mound takes on a faint lime
green appearance. This pale, yellowish-green tint is due to very small particles of
nontronite, a yellowish-green clay, being dispersed throughout the gas hydrate lattice
structure. The evidence is presented in Figure 5.15.
Figure 5.15. Nontronite Dispersed Within Hydrate Matrix This occurrence is not limited to nontronite, however. The phenomena also
persists with kaolinite and bentonite but is not apparent until the hydrate mass has
decomposed, leaving behind a puddle of white-colored water or brownish colored water.
Faint Lime Green Color Within Gas Hydrates
-100-
Two plausible explanations for this are offered. The first explanation is that small
hydrates crystals adhere to fine grain particles and are transported through water-hydrate
capillaries carrying the fine grain particles with them. The second explanation is that
hydrates grow around the fine particles building up layers which effectively displace the
fine grain particles from their original location on the surface of the cup. The first
explanation would be relatively energy intensive compared to the second possibility.
However, biosurfactants’ lowering of surface tension would lessen the energy needed to
carry a fine grain particle through a hydrate capillary making it easier for hydrates to
form rapidly.
CHAPTER VI
CONCLUSIONS
This thesis is the first to document the extent of biosurfactant catalyzation of
natural gas hydrates as a function of concentration and to classify their interactions with
ocean-type sediments.
Significant results were obtained by testing natural gas hydrate formation in the
presence of two biosurfactants, rhamnolipid and Emulsan, and diverse porous media.
The results were dramatically different depending on which biosurfactant was chosen,
hinting at some underlying micellar effect and interaction of media surface with
biosurfactant.
Adsorption
Bentonite was the only surface to effectively adsorb both rhamnolipid and
Emulsan. Its positively charged hydroxyl edges and interlayers effectively attract the
anionic surfactants. Bentonite also has the ability to trap water and biosurfactant within
its interlayers through intercalation. This adsorptive ability along with bentonite’s ability
to structure water give the clay an advantage in hydrate formation that is accentuated in
the presence of biosurfactant.
-102-
Each plot of biosurfactant concentration versus peak formation rate, regardless of
porous media, exhibits the shape of a type of adsorption curve. While hydrate formation
has been likened before to the adsorption process, these data suggest that the type of
adsorption that biosurfactants exhibit on clay surfaces may dictate their ability to catalyze
gas hydrates. Bentonite does this most effectively and therefore exhibits the greatest
catalyzation of natural gas hydrates at each concentration, regardless of biosurfactant or
porous media used.
While differing at lower concentrations (<200 ppm), sand and kaolinite exhibit
similar curves, suggesting that the adsorption of biosurfactants molecules on these
surfaces is minimal (or not present) relative to adsorption exhibited by bentonite.
Adsorption tests also showed that the adsorption of rhamnolipid on sand and kaolinite
might be attributable to admicelles and not to the adsorption of individual biosurfactant
molecules.
Other experiments showed that adsorption of Emulsan onto sediment surfaces is
likely through a C-type or constant affinity attraction (independent of concentration.)
However, adsorption tests ran with Emulsan showed that only bentonite adsorbed
Emulsan to an appreciable extent. The C-type slope of Emulsan concentration versus
peak formation curve could be a manifestation of an increase of nucleating sites as
concentration increases. Yet this explanation does not account for the zero slope of the
curve in the presence of kaolinite. This deactivation of Emulsan on kaolinite may be
attributable to Emulsan spreading on the surface of kaolinite and no longer resembling
the conformation required to promote hydrate catalyzation.
-103-
Formation Rate
Along with the previously mentioned adsorption related trends, trends of peak
formation rate occur for individual sediments. When tested with distilled water,
bentonite again demonstrated the most proficiency in forming hydrates. Nontronite, a
similar smectite clay, did not show any proficiency at catalyzing hydrates as expected.
Apparently, the intercalation of water by bentonite is fundamental in its ability to
kinetically promote gas hydrate formation. To some degree, this fact also disproves the
notion that the hydroxyl edges of the clay are the key players in water structuring for gas
hydrate promotion. The intercalation of water must play another more fundamental role.
Aragonite shows great proficiency for forming gas hydrates with distilled water.
The aragonite structure must be structuring the water in a manner that is kinetically
favorable in the sense of hydrate formation, yet no hydrates visibly form on the surface of
the aragonite. This anomaly is curious but was not studied in depth. All other surfaces
showed no catalytic effect on hydrate formation.
At high concentrations of rhamnolipid (1000 ppm), the peak formation rate
converged for all porous media. Again, a micellar action is suggested. Possibly this
concentration is adequate to negate all adsorption effects (adsorption is at a steady-state
maximum) and allow for hydrate catalysis in the free micellar state. That is, at this point,
free micelles dictate the rate of formation, not adsorbed micelles or adsorbed rhamnolipid
molecules.
Several experiments were also run to determine the effect of heat and mass
transfer on hydrate formation under the conditions of biosurfactant and porous media
interaction. When heat and mass transfer limit hydrate formation, many of the above
-104-
trends are reversed. Most notably, reversal of rhamnolipid concentration versus peak
formation rate occurs in the presence of bentonite. For this scenario, hydrates form very
rapidly in distilled water, but formation slows dramatically when rhamnolipid availability
approaches 1000 ppm.
Hydrate Induction
A correlation between biosurfactants and induction does not exist for the packed
media of these tests. Perhaps this fact is a result of an improper cleaning of tiny particles
from the sediment serving as nucleation sites.
Structure and Preference
The presence of biosurfactant has been shown to have a remarkable effect on the
types of hydrates formed. When hydrates are formed from distilled water, crystal growth
is slow and needle-like in nature. However, when biosurfactant concentration is
increased, the hydrate shape goes through a progression from needle-like, to dendritic, to
nodular, and finally massive. When biosurfactant is in high concentration, the massive
hydrate mounds take on a rounded, structured look accounted for by the ordering
associated with the biosurfactant molecules. Hydrates also seem to grow through
capillary effects where small hydrate clusters are pulled to the surface through hydrate
capillaries. Biosurfactants reduce the energy required to travel through these capillaries.
Natural gas hydrates have a media surface preference. If given the opportunity,
hydrates form at the points of highest porosity and gas concentration. If given the choice
between multiple surfaces, bentonite or nontronite was the preferred choice. Closely
behind the smectites, cold stainless steel was the usual choice. In the presence of any
-105-
other type of sediment, hydrates preferred to form near the stainless steel RTD shield
than any other surface.
Scientific Significance
If natural gas hydrates on the ocean floor are ever to become a viable natural
resource, a fundamental understanding of their environment, their formation, and their
decomposition is needed. Natural gas hydrates exist in a symbiotic world where
microbes, porous media, natural oil and gas, and gas hydrates interact. The promotion of
natural gas hydrates by microorganisms and their metabolic functions is shown in this
thesis to be substantial. Conversely, many organisms need the methane that natural gas
hydrates encase.
This thesis helps explain the large amount of gas hydrates that have been
discovered in ocean sediments in recent years. Biosurfactants produced naturally by
microbes in the ocean-floor ecology catalyze gas hydrate formation in that environment.
These gas hydrates store vast quantities of both biogenic and thermogenic hydrocarbon
gases.
Furthermore, better understanding of the method by which gas hydrates form as
determined in this thesis, especially in marine environments, serves four major purposes.
(1) The means of farming natural gas hydrates in the ocean floor can be better
understood. (2) The additional knowledge gained about gas hydrate formation should
assist the oil and gas industry in foreseeing seafloor instabilities. (3) The understanding
of gas hydrate kinetics affects alternative fuels potential and alternative fuels storage. (4)
Results from this study should be helpful in predicting the location of hydrates in ocean
-106-
sediment, given the stratigraphy of the formations, and in stabilizing global climate
change. Benefits are also foreseen in predicting massive, dispersed or nodular hydrates
in the sea floor.
Summary
1) Biosurfactants promote hydrate growth by increased solubility of gas, reduced
capillary forces, and possibly structuring of water.
2) Biosurfactant concentration versus peak formation rate plots give curves for
each type of sediment indicative of the sediment’s adsorptive properties.
3) Bentonite interlayers and hydroxyl edges increase gas hydrate formation rate
over other surfaces.
4) Bentonite interlayers and hydroxyl edges adsorb individual rhamnolipid
molecules while sand and kaolinite adsorb micelle structures.
5) Kaolinite deactivates Emulsan, not allowing any increase in peak hydrate
formation rate possibly due to Emulsan spreading on kaolinite surfaces.
6) Gas hydrates form needle-like, nodular, dendritic, and massive structures
depending on the biosurfactant-porous media combination.
7) When presented with a choice, gas hydrates prefer to form on porous media
surfaces in the following order: bentonite or nontronite > aragonite or steel >
sand or kaolinite.
8) If heat and mass transfer are rate-limiting steps in hydrate formation,
biosurfactant/porous media effects may be overshadowed.
-107-
REFERENCES [1] M. Faraday, “On Fluid Chlorine,” Transactions of the Royal Society of London,
13 March 1823. [2] E.G. Hammerschmidt, “Formation of Gas Hydrates in Natural Gas Transmission
Lines,” Ind. Eng. Chem., vol. 26, pp. 851 – 855, Aug. 1934. [3] E.D. Sloan, Clathrate Hydrates of Natural Gas. NY: Marcel Dekker, 1990. [4] B.D. Lanoil, et al., “Bacteria and Archaea Physically Associated with Gulf of
Mexico Gas Hydrates,” App. Env. Microbio., vol. 67, no. 11, pp. 5143 – 5153, Nov. 2001.
[5] “TAMU Oceanography: Gas Hydrates,” http://www-
ocean.tamu.edu/Quarterdeck/QD5.3/sassen.html, Accessed 14 June 2004. [6] K. Kvenvolden, “Gas hydrates - Geological Perspective and Global Change”
Reviews of Geophysics, vol. 31, no. 2, pp. 173-187, May 1993. [7] D. Adam, “Fire from ice,” Nature, vol. 415, pp. 913 – 914, 29 Aug. 2002. [8] M.D. Max and W.P. Dillon, “Oceanic Methane Hydrate: The Character of the
Blake Ridge Hydrate Stability Zone, and the Potential for Methane Hydrate Extraction,” J. Petr. Geol., vol. 21, no. 3, pp. 343 – 357, July 1998.
[9] C.N. Murray, et al., “Permanent Storage of Carbon Dioxide in the Marine
Environment: The Solid CO2 Penetrator,” Energy Convers. Mgmt., vol. 37, No. 6 – 8, pp. 1067 – 1072, Aug. 1996.
[10] J.S. Gudmundsson, “Method for Production of Gas Hydrate for Transportation
and Storage,” U.S. Patent 5 536 893, 1996. [11] R.E. Rogers, “Natural Gas Storage Project,” DOE Contract DE-AC26-
97FT33203, US Department of Energy, 1997. [12] W.L. Mao, et al., “Hydrogen Clusters in Clathrate Hydrates,” Science, vol. 297,
pp. 2247 – 2249, Sept. 2002.
-108-
[13] G.Y. Yevi and R.E. Rogers, “Storage of Fuels in Hydrates for Natural Gas Vehicles (NGVs),” J. Energy Res. Tech., vol. 118, pp. 209 – 213, Sept. 1996.
[14] A.J. Barduhn, H.E. Towlson, and Y.C. Hu, “The Properties of Some New Gas
Hydrates and Their Use in Demineralizing Sea Water,” AICHE Journal, vol. 8, no. 2, pp. 176 – 182, May 1962.
[15] E.G. Hammerschmidt, “Gas Hydrate Formations in Natural Gas Pipe Lines,” Oil
Gas J., vol. 37, no. 52, pp. 66 – 72, May 1939. [16] Z. Huo, et al., “Hydrate plug prevention by anti-agglomeration,” Chem. Eng. Sci.,
vol. 56, no. 17, pp. 4979 – 4991, Sept. 2001. [17] T. Appenzeller, “Fire and Ice Under the Deep-Sea Floor,” Science, vol. 252, pp.
1790 – 1792, June 1991. [18] S.P. Hesselbo, et al., “Massive dissociation of gas hydrate during a Jurassic
oceanic anoxic event,” Nature, vol. 406, pp. 392 – 395, July 2000. [19] E.D. Sloan, “Fundamental principles and applications of natural gas hydrates,”
Nature, vol. 426, pp. 353 – 359, 20 Nov. 2003. [20] S.B. Jacobsen, “Gas hydrates and deglaciations,” Nature, vol. 412, pp. 691 – 693,
16 Aug. 2001. [21] M.J. Kennedy, N. Christie-Blick, and L.E. Sohl, “Are Proterozoic cap carbonates
and isotopic excursions a record of gas hydrate destabilization following Earth’s coldest intervals?” Geology, vol. 29, no. 5, pp. 443 – 446, May 2001.
[22] J.A. Ripmeester and C.I. Ratcliffe, “129Xe NMR Studies of Clathrate Hydrates:
New Guests for Structure II and Structure H,” J. Phys. Chem., vol. 94, no. 25, pp. 8773 – 8776, 13 Dec. 1990.
[23] Y.F. Makogon, Hydrates of Natural Gas Tulsa: PennWell, 1981. [24] L.M. Prescott, et al., Microbiology, 5ed. Boston: McGraw-Hill, 2002. [25] N. Kosaric, “Biosurfactants in industry,” Pure and App. Chem., vol. 64, no. 11,
pp. 1731 – 1737, Nov. 1992. [26] C.R. Kothapalli, “Catalysis of gas hydrates by biosurfactants in seawater-
saturated sand/clay,” M.S. Thesis, Mississippi State University, CHE Dept., Starkville, MS, 2002.
-109-
[27] A.J. Hill and S. Ghoshal, “Micellar Solubilization of Naphthalene and Phenanthrene from Nonaqueous-Phase Liquids,” Env. Sci. Tech., vol. 36, no. 18, pp. 3901 – 3907, 15 Sept. 2002.
[28] S. Lang and D. Wullbrandt, “Rhamnose lipids – biosynthesis, microbial
production and application potential,” Appl. Microbiol. Biotechnol., vol. 51, pp. 22 – 32, 1999.
[29] S. Harvey, et al., “Enhanced Removal of Exxon Valdez Spilled Oil From Alaskan
Gravel by a Microbial Surfactant,” Biotechnol., vol. 8, pp. 228 – 230, March 1990.
[30] Y. Zhong and R.E. Rogers, “Surfactant effects on gas hydrate formation,” Chem.
Eng. Sci., vol. 55, no. 19, pp. 4175 – 4187, Oct. 2000. [31] M.S. Lee, “The effects of biosurfactants on gas hydrate formation in ocean
sediments,” M.S. Thesis, Mississippi State University, CHE Dept., Starkville, MS, 2001.
[32] S. Thangamani and G.S. Shreve, “Effect of Anionic Biosurfactant on Hexadecane
Partitioning in Multiphase Systems,” Env. Sci. Tech., vol. 28, no. 12, pp. 1993 – 2000, Nov. 1994.
[33] J.T. Champion, et al., “Electron Microscopy of Rhamnolipid (Biosurfactant)
Morphology: Effects of pH, Cadmium, and Octadecane,” J. Coll. Interf. Sci., vol. 170, no. 2, pp. 569 – 574, 15 Mar. 1995.
[34] “Biodegradable Detergents,”
http://www.natick.army.mil/soldier/media/fact/ss&t/Biodegradable_Detergents.PDF, Accessed 10 May 2004.
[35] E. Rosenberg, “Microbial diversity as a source of useful biopolymers,” J. Ind.
Microbio., vol. 11, no. 3, pp. 131 – 137, May 1993. [36] P.D. Dholabhai, N. Kalogerakis, and P.R. Bishnoi, “Kinetics of Methane Hydrate
Formation in Aqueous Electrolyte Solutions,” Can. J. Chem. Eng., vol. 71, pp. 68 – 74, Feb. 1993.
[37] B. Tohidi, A. Danesh, and A. Todd, “Predicting pipeline hydrate formation,” The
Chem. Eng., iss. 642, pp. 32 – 37, 25 Sept. 1997. [38] M.D. Jager, C.J. Peters, and E.D. Sloan, “Experimental determination of methane
hydrate stability in methanol and electrolyte solutions,” Fluid Phase Eq., vol. 193, iss. 1 – 2, pp. 17 – 28, 30 Jan. 2002.
-110-
[39] D.D. Link, et al., “Formation and dissociation studies for optimizing the uptake of methane by methane hydrates,” Fluid Phase Eq., vol. 211, iss. 1, pp. 1 – 10, 30 Aug. 2003.
[40] G.D. Ginsburg, et al., “24. Sediment Grain-Size Control on Gas Hydrate
Presence, Sites 994, 995, and 997,” in Proc. of the Ocean Drilling Program, Scientific Results, vol. 164, pp. 237 – 245, May 2000.
[41] S.B. Cha, et al., “A Third-Surface Effect on Hydrate Formation,” J. Phys. Chem.,
vol. 92, no. 23, pp. 6492 – 6494, 17 Nov. 1988. [42] R.E. Rogers, et al., “Catalysis of Gas Hydrates by Biosurfactants in Seawater-
Saturated Sand/Clay,” Can. J. Chem. Eng., vol. 81, pp. 973 – 980, Oct. 2003. [43] T. Uchida, T. Ebinuma, and T. Ishizaki, “Dissociation Condition Measurements
of Methane Hydrate in Confined Small Pores of Porous Glass,” J. Phys. Chem. B, vol. 103, no. 18, pp. 3659 – 3662, 6 May 1999.
[44] H.O. Kono and B. Budhijanto, “Modeling of Gas Hydrate Formation by
Controlling the Interfacial Boundary Surfaces,” in Proceedings of the Fourth International Conference on Gas Hydrates, Yokohama, Japan, pp. 461 – 464, May 19 – 23, 2002.
[45] J.K. Mitchell, Fundamentals of Soil Behavior, 2ed. NY: John Wiley and Sons,
1993. [46] J.F. Banfield and K.H. Nealson, “Geomicrobiology: Interactions Between
Microbes and Minerals,” Rev. Mineralogy, vol. 35, pp. 81 – 122, 2004. [47] H.L. Bohn, et al., Soil Chemistry, NY: John Wiley and Sons, 1979. [48] D.G. Vilenskii, Soil Science, Translated by A. Birron and Z.S. Cole, 3ed.
Moscow: State Teachers’ College, 1957. [49] S.M. Lipson and G. Stotzky, “Specificity of virus adsorption to clay minerals,”
Can. J. Microbio., vol. 31, no. 1, pp. 50 – 52, Jan. 1985. [50] J. Grandjean, j. Bujdák, and P. Komadel, “NMR study of surfactant molecules
intercalated in montmorillonite and in silylated montmorillonite,” Clay Minerals, vol. 38, no. 3, pp. 367 – 373, Sept. 2003.
[51] “Sources. Negative Charge:,” http://jan.ucc.nau.edu/~doetqp-
p/courses/env320/lec13/Lec13.html, Accessed 12 May 2004.
-111-
[52] “Solvay Precipitate Calcium Carbonate – Physical Properties,” http://www.solvaypcc.com/safety_environment/0,5261,1000029-_EN,00.html, Accessed 12 May 2004.
[53] “243 Notes Week 10a,”
http://www.usask.ca/geology/classes/geol243/243notes/243week10a.html, Accessed 17 June 2004.
[54] D.J. Shaw, Introduction to Colloid and Surface Chemistry, 3rd ed. London:
Butterworths, 1980. [55] K.L. Mittal, Micellization, Solubilization, and Microemulsions, Vol. 1, NY:
Plenum Press, 1977. [56] “KCPC Education Resource Website: 9.5.5 – Anionic Surfactants,”
http://www.kcpc.usyd.edu.au/discovery/9.5.5-short/9.5.5_anionic.html, Accessed 14 June 2004.
[57] “-- 4: Surface Chemistry --,” http://www.erpt.org/032Q/Nelsc-01.pdf, Accessed
14 June 2004. [58] “KCPC Education Resource Website: 9.5.5 – Cationic Surfactants,”
http://www.kcpc.usyd.edu.au/discovery/9.5.5-short/9.5.5_cationic.html, Accessed 14 June 2004.
[59] “Surfactants ~ Oleochemicals – China GreatVista Chemicals,”
http://www.greatvistachemicals.com/surfactants_and_oleochemicals/, Accessed 14 June 2004.
[60] “KCPC Education Resource Website: 9.5.5 – Nonionic Surfactants,”
http://www.kcpc.usyd.edu.au/discovery/9.5.5-short/9.5.5_nonionic.html, Accessed 14 June 2004.
[61] E.Z. Ron, E. Rosenberg, “Natural roles of biosurfactants,” Envir. Microbio., vol.
3, no. 4, pp. 229 – 236, 2001. [62] R.M. Miller, “Biosurfactant-facilitated Remediation of Metal-contaminated
Soils,” Environmental Health Perspectives, vol. 103, suppl. 1, pp. 59 – 62, Feb. 1995.
[63] M.U. Jianhai, et al., “Formation of wormlike micelles in anionic surfactant AES
aqueous solutions,” Chinese Science Bulletin, vol. 46, no. 16, pp. 1360 – 1364, Aug. 2001.
-112-
[64] Z.A. Al-Anber, M.A. Floriano, and A.D. Mackie, “Sphere-to-rod transitions of micelles in model nonionic surfactant solutions,” J. Chem. Phys., vol. 118, no. 8, pp. 3816 – 3826, Feb. 2003.
[65] S. Roy, A. Mehra, and D. Bhowmick, “Prediction of Solubility of Nonpolar Gases
in Micellar Solutions of Ionic Surfactants,” J. Coll. Interf. Sci., vol. 196, no. 1, pp. 53 – 61, 1 Dec. 1997.
[66] R.A. Al-Tahhan, et al., “Rhamnolipid-Induced Removal of Lipopolysaccharide
from Pseudomonas aeruginosa: Effect on Cell Surface Properties and Interaction with Hydrophobic Substrates,” App. Envir. Microbio., vol. 66, no. 8, pp. 3262 – 3268, Aug. 2000.
[67] N. Li, S. Liu, and H. Luo, “A New Method for the Determination of the First and
Second CMC in CTAB Solution by Resonance Rayleigh Scattering Technology,” Analytical Letters, vol. 35, no. 7, pp. 1229 – 1238, May 2002.
[68] D.L. Gutnick, “The Emulsan Polymer: Perspectives on a Microbial Capsule as an
Industrial Product,” Biopolymers, 26, pp. S223 – S240, 1987. [69] M.E. Sumner, Handbook of Soil Science, Boca Raton, FL: CRC Press, 2000. [70] “ENSC 4734 Topic VI Sorption Phenomena,”
http://soils1.cses.vt.edu/MJE/ENSC4734/Slides/Topic6.pdf, Accessed 29 May 2004.
[71] A. Vysniauskas and P.R. Bishnoi, “A Kinetic Study of Methane Hydrate
Formation,” Chem. Eng. Sci., vol. 38, no. 7, pp. 1061 – 1072, July 1983. [72] V.M. Starov, S.A. Zhdanov, and M.G. Velarde, “Capillary imbibition of
surfactant solutions in porous media and thin capillaries: partial wetting case,” J. Coll. and Interf. Sci., vol. 273, no.2, pp. 589 – 595, 15 May 2004.
[73] D. Kashchiev and A. Firoozabadi, “Induction time in crystallization of gas
hydrates,” J. Crystal Growth, vol. 250, iss. 3 – 4, pp. 499 – 515, Apr. 2003. [74] A. Vysniauskas and P.R. Bishnoi, “Kinetics Study of Ethane Hydrate Formation,”
Chem. Eng. Sci., vol. 40, no. 2, pp. 299 – 303, Feb. 1985. [75] F. Varaminian, “The Role of Heat Transfer in Kinetics of Hydrate Formation,” in
Proceedings of the Fourth International Conference on Gas Hydrates, Yokohama, Japan, pp. 465 – 468, May 19 – 23, 2002.
-113-
[76] M. Mork, J.S. Gudmundsson, and M. Parlaktuna, “Hydrate Formation Rate in a Continuous Stirred Tank Reactor,” presented at 2001 International Gas Research Conference, Amsterdam, The Netherlands, November 5 – 8, 2001.
[77] P. Englezos and P.R. Bishnoi, “Prediction of Gas Hydrate Formation Conditions
in Aqueous Electrolyte Solutions,” AIChE Journal, vol. 34, no. 10, pp. 1718 – 1721, Oct. 1988.
[78] J.L. Roo, et al., “Occurrence of Methane Hydrate in Saturated and Unsaturated
Solutions of Sodium Chloride and Water in Dependence of Temperature and Pressure,” AIChE Journal, vol. 29, no. 4, pp. 651 – 657, July 1983.
-114-
APPENDIX A
Experimental Data
Table A.1. Experimental Plan
Conc. Run # Surface Biosurfactant
Surf. Tension (mN/m) (ppm)
Ionic Content
Amt of Sand (g)
Amt of Bentonite (g)
Amt of Kaolinite (g)
Amt of Nontronite (g)
Amt of Carbonate (g)
100 Sand Rhamnolipid 27.0 1000 DI Water 70 0 0 0 0 101 Sand Rhamnolipid 29.8 100 DI Water 70 0 0 0 0 102 Sand Rhamnolipid 54.6 10 DI Water 70 0 0 0 0 103 Sand None 73.8 0 DI Water 70 0 0 0 0 104 Sand/Bent Rhamnolipid 26.8 1000 DI Water 67 3 0 0 0 105 Sand/Bent Rhamnolipid 30.2 100 DI Water 67 3 0 0 0 106 Sand/Bent Rhamnolipid 54.6 10 DI Water 67 3 0 0 0 107 Sand/Bent None 72.8 0 DI Water 67 3 0 0 0 108 Sand/Kaol Rhamnolipid 27.2 1000 DI Water 67 0 3 0 0 109 Sand/Kaol Rhamnolipid 29.9 100 DI Water 67 0 3 0 0 110 Sand/Kaol Rhamnolipid 46.2 10 DI Water 67 0 3 0 0 111 Sand/Kaol None 72.9 0 DI Water 67 0 3 0 0 112 Sand Emulsan 40.7 1000 DI Water 70 0 0 0 0 113 Sand Emulsan 44.4 100 DI Water 70 0 0 0 0 114 Sand Emulsan 62.2 10 DI Water 70 0 0 0 0 115 Sand/Bent Emulsan 40.6 1000 DI Water 67 3 0 0 0 116 Sand/Bent Emulsan 43.9 100 DI Water 67 3 0 0 0 117 Sand/Bent Emulsan 56.5 10 DI Water 67 3 0 0 0 118 Sand/Kaol Emulsan 41.9 1000 DI Water 67 0 3 0 0 119 Sand/Kaol Emulsan 44.9 100 DI Water 67 0 3 0 0 120 Sand/Kaol Emulsan 62.1 10 DI Water 67 0 3 0 0 121 Sand None 73.3 0 Seawater 70 0 0 0 0 122 Sand Rhamnolipid 26.3 1000 Seawater 70 0 0 0 0 125 Sand/Nont None 73.3 0 DI Water 67 0 0 3 0 126 Sand/Carb None 73.4 0 DI Water 67 0 0 0 3 127 Sand/Nont Rhamnolipid 27.3 1000 DI Water 67 0 0 3 0 128 Sand/Carb Rhamnolipid 26.9 1000 DI Water 67 0 0 0 3
-115-
Table A.1. Experimental Plan (Cont’d)
Conc. Run # Surface Biosurfactant
Surf. Tension (mN/m) (ppm)
Ionic Content
Amt of Sand (g)
Amt of Bentonite (g)
Amt of Kaolinite (g)
Amt of Nontronite (g)
Amt of Carbonate (g)
130 Sand Rhamnolipid 27.5 1000 DI Water 70 0 0 0 0 131 Sand Rhamnolipid 30.0 100 DI Water 70 0 0 0 0 132 Sand Rhamnolipid 54.4 10 DI Water 70 0 0 0 0 133 Sand None 72.3 0 DI Water 70 0 0 0 0 134 Sand/Bent Rhamnolipid 27.1 1000 DI Water 67 3 0 0 0 135 Sand/Bent Rhamnolipid 30.3 100 DI Water 67 3 0 0 0 136 Sand/Bent Rhamnolipid 49.9 10 DI Water 67 3 0 0 0 137 Sand/Bent None 73.4 0 DI Water 67 3 0 0 0 138 Sand/Kaol Rhamnolipid 27.4 1000 DI Water 67 0 3 0 0 139 Sand/Kaol Rhamnolipid 30.2 100 DI Water 67 0 3 0 0 140 Sand/Kaol Rhamnolipid 58.5 10 DI Water 67 0 3 0 0 141 Sand/Kaol None 73.2 0 DI Water 67 0 3 0 0 142 Sand Emulsan 39.7 1000 DI Water 70 0 0 0 0 143 Sand Emulsan 44.7 100 DI Water 70 0 0 0 0 144 Sand Emulsan 62.8 10 DI Water 70 0 0 0 0 145 Sand/Bent Emulsan 39.2 1000 DI Water 67 3 0 0 0 146 Sand/Bent Emulsan 45.1 100 DI Water 67 3 0 0 0 147 Sand/Bent Emulsan 56.8 10 DI Water 67 3 0 0 0 148 Sand/Kaol Emulsan 38.6 1000 DI Water 67 0 3 0 0 149 Sand/Kaol Emulsan 44.8 100 DI Water 67 0 3 0 0 150 Sand/Kaol Emulsan 63.4 10 DI Water 67 0 3 0 0 151 Sand None 73.0 0 Seawater 70 0 0 0 0 152 Sand Rhamnolipid 26.8 1000 Seawater 70 0 0 0 0 155 Sand/Nont None 72.8 0 DI Water 67 0 0 3 0 156 Sand/Carb None 72.6 0 DI Water 67 0 0 0 3 157 Sand/Nont Rhamnolipid 27.4 1000 DI Water 67 0 0 3 0
-116-
Table A.1. Experimental Plan (Cont’d)
Conc. Run # Surface Biosurfactant
Surf. Tension (mN/m) (ppm)
Ionic Content
Amt of Sand (g)
Amt of Bentonite (g)
Amt of Kaolinite (g)
Amt of Nontronite (g)
Amt of Carbonate (g)
158 Sand/Carb Rhamnolipid 27.3 1000 DI Water 67 0 0 0 3 160 Sand Rhamnolipid 27.0 500 DI Water 70 0 0 0 0 161 Sand Rhamnolipid 27.5 500 DI Water 70 0 0 0 0 162 Sand Emulsan 41.2 500 DI Water 70 0 0 0 0 163 Sand Emulsan 42.1 500 DI Water 70 0 0 0 0 164 Sand/Bent Rhamnolipid 27.6 500 DI Water 67 3 0 0 0 165 Sand/Bent Rhamnolipid 27.3 500 DI Water 67 3 0 0 0 166 Sand/Bent Emulsan 41.1 500 DI Water 67 3 0 0 0 167 Sand/Bent Emulsan 41.8 500 DI Water 67 3 0 0 0 168 Sand/Kaol Rhamnolipid 27.1 500 DI Water 67 0 3 0 0 169 Sand/Kaol Rhamnolipid 27.5 500 DI Water 67 0 3 0 0 172 Sand Emulsan 45.8 100 DI Water 70 0 0 0 0 173 Sand/Kaol Rhamnolipid 27.0 1000 DI Water 67 0 3 0 0 174 Sand None 72.9 0 DI Water 70 0 0 0 0 175 Sand Rhamnolipid 49.2 10 DI Water 70 0 0 0 0 176 Sand Emulsan 43.8 100 DI Water 70 0 0 0 0 177 Sand Emulsan 61.9 10 DI Water 70 0 0 0 0 179 Sand Rhamnolipid 27.1 1000 DI Water 70 0 0 0 0 180 Sand/Bent Rhamnolipid 29.7 100 DI Water 67 3 0 0 0 181 Sand/Kaol Rhamnolipid 27.5 1000 DI Water 67 0 3 0 0 182 Sand/Kaol Rhamnolipid 26.5 500 DI Water 67 0 3 0 0 183 Sand/Bent Emulsan 39.2 1000 DI Water 67 3 0 0 0 184 Sand Rhamnolipid 26.1 1000 Seawater 70 0 0 0 0 185 Sand Emulsan 40.1 500 Seawater 70 0 0 0 0
-117-
-118-
Table A.2. Surface Tension of Rhamnolipid at Room & Hydrate Temperature
Rhamnolipid/Distilled Water
Concentration (ppm)
Surf. Tension @ 35oF (mN/m)
Surf. Tension @ Room Temp.(mN/m)
0 65.7 70.2 10 49.9 46.9 20 46.3 42.0 30 43.9 39.9 40 41.3 37.3 50 41.2 35.4 60 38.2 35.3 70 36.1 33.2 80 36.4 32.1 90 35.7 31.4 100 34.0 31.7 250 31.0 29.5 500 30.4 28.8 1000 29.4 28.3
Table A.3. Surface Tension of Emulsan at Room Temperature
Emulsan/Distilled Water
Concentration (ppm)
Surf. Tension @ Room Temp. (mN/m)
0 73.4 10 55.1 20 53.7 30 47.8 40 47.4 50 47.7 60 43.3 70 43.2 80 43.1 90 43.4 100 43.7 200 41.1 300 41.2 400 41.2 500 40.8 1000 40.4
-119-
25.0
30.0
35.0
40.0
45.0
50.0
55.0
60.0
65.0
70.0
75.0
0 200 400 600 800 1000
Concentration Rhamnolipid (ppm)
Surf
ace
Tens
ion
(mN
/m)
Rhamn./DW @RT Rhamn./DW @35oF
Figure A.1. CMC of Rhamnolipid at Room & Refrigerated Temperature
35.0
40.0
45.0
50.0
55.0
60.0
65.0
70.0
75.0
0 200 400 600 800 1000
Concentration Rhamnolipid (ppm)
Surf
ace
Tens
ion
(mN
/m)
Emulsan @RT
Figure A.2. ST Vs Concentration of Emulsan at Room Temperature
Table A.4. Heat & Mass Transfer Effects on Hydrate Formation (Fig. 5.10) Run # Surface Surfactant Surf. Tension Conc. pH Induction Time Peak Formation Rate
(mN/m) (ppm) (hrs.) (mmol/min) 25 Sand/Bent None 70.3 0 -- 24.10 40.03 32 Sand/Bent None 73.3 0 -- 0.95 29.35 37 Sand/Bent None 73.4 0 22.58 66.35 13 Sand/Bent Rhamno 56.4 10 6.90 6.53 34.16 14 Sand/Bent Rhamno 57.7 10 6.70 1.30 26.16 15 Sand/Bent Rhamno 54.9 10 -- 1.50 28.17 4 Sand/Bent Rhamno 33.2 100 -- 0.60 12.22 5 Sand/Bent Rhamno 32.8 100 -- 0.77 12.14 6 Sand/Bent Rhamno 33.1 100 -- 0.70 18.02 8 Sand/Bent Rhamno 28.3 1000 6.49 0.95 7.61
11 Sand/Bent Rhamno 28.3 1000 6.54 5.58 10.65 12 Sand/Bent Rhamno 28.0 1000 6.46 7.43 8.35
Table A.5. Effect of Rhamnolipid on Ottawa Sand, Averaged (Fig. 5.6)
Rhamnolipid
Concentration (ppm)Ottawa Sand, Peak Form.
Rate (mmol/min) STDEV 0 0.54 0.04
10 0.49 #DIV/0! 100 0.80 0.20 500 1.62 0.00
1000 1.64 0.32
-120-
-121-
Table A.6. Effect of Rhamnolipid on Ottawa Sand/Bentonite, Averaged (Fig. 5.7)
Rhamnolipid
Concentration (ppm) OS/Bent. Peak Form.
Rate (mmol/min) STDEV
0 0.90 0.25 10 0.93 0.25
100 1.89 0.35 500 2.31 0.05
1000 1.50 0.00 Table A.7. Effect of Rhamnolipid on Ottawa Sand/Kaolinite, Averaged (Fig. 5.8)
Rhamnolipid
Concentration (ppm) OS/Kaolin Peak Form.
Rate (mmol/min) STDEV
0 0.45 0.04 10 0.48 0.06
100 0.50 0.02 500 1.16 0.42
1000 1.70 0.33 Table A.8. Effect of Emulsan on Ottawa Sand, Averaged (Fig. 5.4)
Emulsan
Concentration (ppm) Ottawa Sand, Peak Form.
Rate (mmol/min) STDEV
0 0.54 0.04 10 0.83 0.07
100 0.62 #DIV/0! 1000 1.49 0.11
-122-
Table A.9. Effect of Emulsan on Ottawa Sand/Bentonite, Averaged (Fig. 5.4)
Emulsan
Concentration (ppm) OS/Bent. Peak Form. Rate
(mmol/min) STDEV
0 0.90 0.25 10 0.98 0.04
100 1.07 0.12 500 1.80 0.25
1000 1.93 0.66 Table A.10. Effect of Emulsan on Ottawa Sand/Kaolinite, Averaged (Fig. 5.4)
Emulsan
Concentration (ppm) OS/Kaolin Peak Form. Rate
(mmol/min) STDEV
0 0.45 0.04 10 0.36 0.00
100 0.43 #DIV/0! 1000 0.39 0.04
Table A.11. Effect of Rhamnolipid on Varied Surfaces, Averaged (Fig. 5.3, 5.5)
Ottawa Sand OS/Bentonite OS/Kaolinite OS/Nontronite OS/Aragonite
Concentration (ppm)
Peak Form. Rate
(mmol/min) STDEV
Peak Form. Rate
(mmol/min) STDEV
Peak Form. Rate
(mmol/min) STDEV
Peak Form. Rate
(mmol/min) STDEV
Peak Form. Rate
(mmol/min) STDEV 0 0.54 0.04 0.90 0.25 0.45 0.04 0.40 0.13 0.75 0.00
1000 1.64 0.32 1.50 0.00 1.70 0.33 1.59 0.37 1.42 0.15 Table A.12. Compiled Experimental Data
Surf. Tension Conc. Ind. TimeInitial Hydrate
Form. Rate Average-to-Peak
Form. Rate Peak Form.
Rate ∆ntot Run # Surface Surfactant (mN/m) (ppm) (hrs.) (mmol/min) (mmol/min) (mmol/min) (mmoles) 100 Sand Rhamnolipid 27.0 1000 2.53 0.86 1.16 1.99 81.63 130 Sand Rhamnolipid 27.5 1000 13.18 0.90 0.80 1.35 88.41 179 Sand Rhamnolipid 27.1 1000 11.40 0.74 0.93 1.59 90.03 160 Sand Rhamnolipid 27.0 500 75.38 1.04 0.66 1.62 90.23 161 Sand Rhamnolipid 27.5 500 5.89 0.99 0.96 1.62 90.83 101 Sand Rhamnolipid 29.8 100 1.79 0.44 0.30 0.66 31.16 131 Sand Rhamnolipid 30.0 100 1.20 0.09 0.33 0.94 91.09 102 Sand Rhamnolipid 54.6 10 >48 n/a n/a n/a 5.48 132 Sand Rhamnolipid 54.4 10 6.67 0.08 0.11 0.49 56.68 175 Sand Rhamnolipid 49.2 10 >48 n/a n/a n/a n/a 103 Sand None 73.8 0 >48 n/a n/a n/a 0.00 133 Sand None 72.3 0 11.63 0.23 0.17 0.56 78.25
-123-
Table A.12. Compiled Experimental Data (Cont’d)
Surf. Tension Conc. Ind. TimeInitial Hydrate
Form. Rate Average-to-Peak
Form. Rate Peak Form.
Rate ∆ntot Run # Surface Surfactant (mN/m) (ppm) (hrs.) (mmol/min) (mmol/min) (mmol/min) (mmoles)174 Sand None 72.9 0 3.90 0.06 0.23 0.51 77.58 104 Sand/Bent Rhamnolipid 26.8 1000 3.74 0.71 0.71 1.50 88.30 134 Sand/Bent Rhamnolipid 27.1 1000 25.79 0.79 0.72 1.50 91.06 164 Sand/Bent Rhamnolipid 27.6 500 1.15 1.26 1.08 2.27 91.93 165 Sand/Bent Rhamnolipid 27.3 500 2.11 1.99 0.99 2.34 89.56 105 Sand/Bent Rhamnolipid 30.2 100 1.62 1.37 1.20 2.27 92.06 135 Sand/Bent Rhamnolipid 30.3 100 1.33 1.16 0.92 1.79 89.19 180 Sand/Bent Rhamnolipid 29.7 100 3.98 n/a n/a 1.60 93.37 106 Sand/Bent Rhamnolipid 54.6 10 4.88 0.55 0.53 0.75 58.88 136 Sand/Bent Rhamnolipid 49.9 10 7.98 n/a n/a 1.11 77.74 107 Sand/Bent None 72.8 0 0.96 0.50 0.44 0.72 57.53 137 Sand/Bent None 73.4 0 3.68 0.70 0.68 1.08 77.88 108 Sand/Kaol Rhamnolipid 27.2 1000 2.52 1.19 0.76 1.89 81.45 138 Sand/Kaol Rhamnolipid 27.4 1000 >48 n/a n/a n/a 0.00 173 Sand/Kaol Rhamnolipid 27.0 1000 1.80 0.89 0.81 1.32 80.44 181 Sand/Kaol Rhamnolipid 27.5 1000 1.50 0.82 0.89 1.88 74.09 168 Sand/Kaol Rhamnolipid 27.1 500 7.93 0.26 0.32 0.67 78.96 169 Sand/Kaol Rhamnolipid 27.5 500 3.53 0.80 0.77 1.36 79.54 182 Sand/Kaol Rhamnolipid 26.5 500 3.37 0.27 0.51 1.44 86.29 109 Sand/Kaol Rhamnolipid 29.9 100 1.79 0.09 0.13 0.51 72.91 139 Sand/Kaol Rhamnolipid 30.2 100 4.67 0.14 0.02 0.48 91.05 110 Sand/Kaol Rhamnolipid 46.2 10 5.46 0.04 0.09 0.52 53.87 140 Sand/Kaol Rhamnolipid 58.5 10 2.35 n/a n/a 0.43 67.90 111 Sand/Kaol None 72.9 0 2.18 0.02 0.03 0.42 50.89 141 Sand/Kaol None 73.2 0 5.28 n/a n/a 0.48 70.19
-124-
Table A.12. Compiled Experimental Data (Cont’d)
Surf. Tension Conc. Ind. TimeInitial Hydrate
Form. Rate Average-to-Peak
Form. Rate Peak Form.
Rate ∆ntot Run # Surface Surfactant (mN/m) (ppm) (hrs.) (mmol/min) (mmol/min) (mmol/min) (moles) 112 Sand Emulsan 40.7 1000 6.58 0.23 0.73 1.41 85.02 142 Sand Emulsan 39.7 1000 23.10 0.28 0.76 1.56 89.79 162 Sand Emulsan 41.2 500 6.63 0.18 0.13 0.43 10.21 163 Sand Emulsan 42.1 500 14.68 0.11 0.07 0.43 6.61 185 Sand Emulsan 40.1 500 11.09 n/a n/a 0.43 16.27 113 Sand Emulsan 44.4 100 >48 n/a n/a n/a 15.63 143 Sand Emulsan 44.7 100 >48 n/a n/a n/a 0.00 172 Sand Emulsan 45.8 100 1.51 0.29 0.28 0.62 54.32 176 Sand Emulsan 43.8 100 >48 n/a n/a n/a 0.00 114 Sand Emulsan 62.2 10 >48 n/a n/a n/a 3.73 144 Sand Emulsan 62.8 10 0.99 0.11 0.24 0.78 67.00 177 Sand Emulsan 61.9 10 12.18 n/a n/a 0.88 64.18 115 Sand/Bent Emulsan 40.6 1000 4.47 0.74 1.19 2.68 87.09 145 Sand/Bent Emulsan 39.2 1000 1.58 0.35 0.81 1.47 90.49 183 Sand/Bent Emulsan 39.2 1000 9.47 n/a n/a 1.63 85.26 166 Sand/Bent Emulsan 41.1 500 3.78 1.06 1.22 1.98 88.18 167 Sand/Bent Emulsan 41.8 500 2.23 0.73 1.12 1.62 85.78 116 Sand/Bent Emulsan 43.9 100 3.33 0.64 0.58 0.98 70.43 146 Sand/Bent Emulsan 45.1 100 1.13 0.82 0.69 1.15 82.29 117 Sand/Bent Emulsan 56.5 10 5.74 n/a n/a 1.01 81.31
-125-
Table A.12. Compiled Experimental Data (Cont’d)
Surf.
Tension Conc. Ind. TimeInitial Hydrate
Form. Rate Average-to-Peak
Form. Rate Peak Form.
Rate ∆ntot Run # Surface Surfactant (mN/m) (ppm) (hrs.) (mmol/min) (mmol/min) (mmol/min) (moles) 147 Sand/Bent Emulsan 56.8 10 1.47 n/a n/a 0.95 85.86 118 Sand/Kaol Emulsan 41.9 1000 3.98 0.03 0.05 0.36 53.21 148 Sand/Kaol Emulsan 38.6 1000 2.98 n/a n/a 0.42 68.17 119 Sand/Kaol Emulsan 44.9 100 10.88 n/a n/a 0.43 19.12 149 Sand/Kaol Emulsan 44.8 100 >48 n/a n/a n/a 0.00 120 Sand/Kaol Emulsan 62.1 10 32.23 n/a n/a 0.36 16.07 150 Sand/Kaol Emulsan 63.4 10 >48 n/a n/a 0.36 17.94 121 Sand None/SW 73.3 0 4.73 0.05 0.04 0.42 55.11 151 Sand None/SW 73.0 0 6.52 0.03 0.03 0.36 62.73 122 Sand Rhamnolipid/SW 26.3 1000 3.39 0.91 0.63 1.24 73.37 152 Sand Rhamnolipid/SW 26.8 1000 5.34 0.74 0.30 1.93 74.78 184 Sand Rhamnolipid/SW 26.1 1000 3.03 0.62 0.61 1.24 71.05 125 Sand/Nont None 73.3 0 9.19 0.03 0.07 0.30 33.05 155 Sand/Nont None 72.8 0 >48 n/a n/a 0.49 12.34 126 Sand/Carb None 73.4 0 0.43 0.42 0.31 0.75 74.12 156 Sand/Carb None 72.6 0 0.77 0.37 0.39 0.75 73.29 127 Sand/Nont Rhamnolipid 27.3 1000 10.13 1.32 1.27 1.85 85.62 157 Sand/Nont Rhamnolipid 27.4 1000 2.62 1.15 0.69 1.33 84.90 128 Sand/Carb Rhamnolipid 26.9 1000 0.70 0.63 0.78 1.31 88.95 158 Sand/Carb Rhamnolipid 27.3 1000 33.93 0.58 0.81 1.52 85.49
-126-
-127-
APPENDIX B
Peng-Robinson Calculations
-128-
Given: Initial Temperature, Ti = 274.83K Final Temperature, Tf = 274.90K Initial Pressure, Pi = 19.95 atm Final Pressure, Pf = 19.90 atm Volume, V = 440 ml Time, ∆t = 30 sec. Critical Temperature, Tc = 204.656 K Critical Pressure, Pc = 45.43 atm Acentric Factor, ω = 0.01916
( ) ( ) ( )32223 2310)( BBABzBBAzBzzf −−−⋅−−+⋅+−==
2
)(45724.0
r
r
TPA ⋅⋅
=ωα
r
r
TPB ⋅
=0778.0
( ) ( )[ ]25.02 126992.054226.137464.01)( rTa −⋅+++= ωωω
cr P
PP =
cr T
TT =
92878.0=fz
92853.0=iz
⋅−
⋅
⋅⋅
=
−⋅=∆
274.83K0.9285395.19
274.90K0.9287890.19
08206.0
440.0 atmatm
KmolatmL
LTz
PTz
PRVn
ii
i
ff
f
mmolmoleEn 34.1334.1 =−=∆
min/68.2min5.0
34.1 mmolmmoltnrformation ==
∆∆
=−
