Hydrate formation in gas pipelines

EASTERN MACEDONIA AND THRACE INSTITUTE OF TECHNOLOGY
FACULTY OF ENGINEERING
DEPARTMENT OF PETROLEUM AND NATURAL GAS TECHNOLOGY
MSc in OIL AND GAS TECHNOLOGY
COURSE ASSIGNMENT FOR “OIL & GAS MANAGEMENT”
METHANE HYDRATE FORMATION IN NATURAL GAS
PIPELINES
ELISAVET MICHAILIDI
B.Sc. Petroleum Engineering
ARISTIDIS MITSIS
M.Sc. Civil Engineering
FOTIS ZACHOPOULOS
B.Sc. Petroleum Engineering
SUPERVISOR: ADJ. PROF. NIKOLAOS C. KOKKINOS
KAVALA 2014

ABSTRACT
The current assignment discusses the formation of natural gas hydrates in gas
transmission pipelines. Hydrates are crystalline compounds, consisting of a gas
molecule and water, which form under certain thermodynamic conditions, which include
high pressure and low temperature. Natural gas hydrates are responsible for pipeline
plugging and corrosion. Thus, handling the issue of the formation is a matter of vital
importance for the industry. At the theoretical background of the assignment the topic is
presented and analyzed towards the hydrate structure and development, the formation,
the consequences and, finally, the solutions as well as the inspection processes. In
order to provide the optimal strategy in dealing with hydrate formation, it is of vital
importance to have an understanding of the conditions that cause hydrate formation.
The most accurate predictions can be conducted with the use of computer software. In
the current assignment the chemical simulations software Aspen Hysys is used for
studying the formation conditions. Three potential natural gas streams, with different
compositions, were modeled and studied towards the conditions of hydrate formation.
SUBJECT AREA: Natural Gas Hydrates
KEYWORDS: gas hydrates, hydrate prediction, hydrate formation, inhibitors, hydrate
structure

A.Mitsis E.Michailidi F.Zachopoulos - 7 - 2014
TABLE OF CONTENTS
1. CHAPTER 1 INTRODUCTION ........................................................................................12
1.1 INTRODUCTION .........................................................................................................12
2. CHAPTER 2 THEORETICAL BACKGROUND............................................................13
2.1 HYDRATES STRUCTURE.........................................................................................13
2.1.1 METHANE HYDRATES ......................................................................................15
2.2 HYDRATE DEVELOPMENT......................................................................................16
2.3 HYDRATE FORMATION............................................................................................16
2.4 HYDRATES EFFECTS IN GAS PIPELINES...........................................................18
2.4.1 HYDRATE FORMATIONS AS INITIATORS OF NATURAL GAS PIPELINE
INTERNAL CORROSIONS...............................................................................................19
2.5 SOLUTIONS TO THE HYDRATE FORMATION PROBLEMS.............................22
2.5.1 CHEMICAL INJECTION......................................................................................22
2.5.2 NATURAL GAS DEHYDRATION ......................................................................24
2.6 MAINTENANCE AND DETECTION OPERATIONS ..............................................25
2.6.1 OPTlMAL TRANSMISION OPERATIONS DESIGN.......................................25
2.6.2 REGULAR PIPE INSPECTION AND PIGGING OPERATIONS...................26
3. CHAPTER 3 EXPERIMENTAL PROCEDURE.............................................................27
3.1 PREDICTION OF HYDRATE FORMATION USING COMPUTER SOFTWARE
27
3.2 EXPERIMENTAL PROCEDURE...............................................................................27
4. CHAPTER 4 CONCLUSIONS..........................................................................................33
5. ABBREVIATIONS – INITIALS.....................................................................................34
6. REFERENCES....................................................................................................................36

LIST OF FIGURES
Figure 2.1 Three hydrate unit crystals and constituent cavities[14] .....................................14
Figure 2.2 (a) Linking five 512 polyhedra by two 51262 polyhedra to form structure I (b)
Two-dimensional view of face-sharing of 512 polyhedra to form 51264 polyhedra voids for
structure II[9] .................................................................................................................................15
Figure 2.3 Hydrate development..............................................................................................16
Figure 2.4 Pressure/temperature diagram for methane + water in the hydrate region[18]
.......................................................................................................................................................17
Figure 2.5 Gas + single condensate + water systems[18] .....................................................18
Figure 2.6: The "Horseshoe" type erosion-corrosion damage in a copper pipeline[2] .....21
Figure 2.7: Generic Hydrate Formation Curve. The properties of Petroleum Fluids[1] ....23
Figure 2.8: Temperature-Composition diagram for Methane and Water.[18] .....................24
Figure 3.1 Hydrate Formation utility Sweet Gas Design ......................................................28
Figure 3.2 Hydrate Formation Utility Sweet Gas Performance ...........................................29
Figure 3.3 Hydrate Formation Utility Sweet Gas + CO2 Design .........................................29
Figure 3.4 Hydrate Formation Utility Sweet Gas + CO2 Performance...............................30
Figure 3.5 Hydrate Formation Utility Sour Gas + CO2 Design ............................................30
Figure 3.6 Hydrate Formation Utility Sour Gas + CO2 Performance..................................31
Figure 3.7 Sweet Gas Envelope ..............................................................................................31
Figure 3.8 Sweet Gas + CO2 Envelope ..................................................................................32
Figure 3.9 Sour Gas + CO2 Envelope.....................................................................................32

HYDRATE FORMATION IN GAS PIPELINES DEPARTMENT OF PETROLEUM AND NATURAL GAS TECHNOLOGY
LIST OF TABLES
Table 2.1 Properties of gas hydrate structures[13] .................................................................13
Table 3.1 Stream Composition.................................................................................................27
Table 3.2 Initial Conditions........................................................................................................28

1. CHAPTER 1
INTRODUCTION
1.1 INTRODUCTION
During the natural gas transportation through pipelines and under certain
thermodynamic conditions, considering pressure, temperature and composition,
crystalline compounds, consisting of a gas molecule and water, are formed. These ice-
like compounds are known as “gas hydrates” or “gas clathrates”. The term “clathrate”
has its origins in the Greek language as it derives from the word “khlatron”[3] which
means barrier. Gas hydrates are formed from a gas molecule, which is called “guest
molecule”, trapped within a hydrogen-bonded structure of water molecules, called “host
molecules”[4].
Hydrates were discovered in 1810 by Sir Humphry Davy and experimentally approved
by John Faraday in 1820[5]. In 1934 Hammerschmit[6] observed that the formation of
gas hydrates was responsible for oil and gas transportation pipelines blockage. The
formation of methane hydrates in the pipelines during the natural gas transportation is a
major concern for the oil and gas industry as it is responsible for plugging the pipelines
and corrosion[2]. Hence, since then, many studies have been conducted concerning a
variety of aspects, including the structure, the kinetics[7], the formation conditions, the
prediction of formation[8], the effects as well as the inhibition of the hydrates formation
which is a highly concerned matter due to its cost for the industry.
In order to provide the best possible strategy in dealing with hydrate formation, it is of
vital importance to have a comprehensive understanding of the underlying conditions
that lead to initial hydrate formation. Computer software are powerful tools for the
prediction of the hydrate formation. In the current assignment the simulation software
Aspen Hysys is used for the prediction of three different streams of natural gas and the
results are presented and analyzed.

2. CHAPTER 2
THEORETICAL BACKGROUND
2.1 HYDRATES STRUCTURE
Gas hydrates are crystalline solid compounds consisting of a low molar weight gas
molecule trapped within a structure of hydrogen-bonded water molecules. Gas hydrates
are formed from a gas molecule, which is called “guest molecule”, trapped within a
hydrogen-bonded structure of water molecules, called “host molecules” in a structure
which resembles a cage[9]. The general formula is M+NH H2O=M×NH H2O,
where NH=the hydration number and M the hydrocarbon molecule[10].
Depending on the type and number of cavities and various sizes of guest molecules -
which cause the different arrangements of water molecules, hydrates are categorized
into three different structure types[11].
Each structure includes different types of molecules depending to the guest molecule
size[8]. Thus, structure I allows the inclusion of methane, ethane and carbon dioxide;
Structure II allows inclusion of propane and iso-butane along with methane and ethane.
Finally, structure H includes heavier molecules. Natural gas hydrates can consist of any
combination of the structures sI and s II depending to its composition[8]. Structure H is
yet to be found outside laboratory[12]. The main properties of the different types of
structures are presented in Table 2.1.
Table 2.1 Properties of gas hydrate structures[13]
The unit cell of structure I (sI)[9, 11, 13] is consisted of 46 water molecules. Two types of
cavities are formed - two small which have the shape of a pentagonal dodecahedron

(512) and six large which have the shape of a hexagonal truncated trapezohedron
(51262). Hydrates of this category are consisted from a single guest molecule of low
molecular weight. The average cavity radius is 3.96 Å for the small cavities and 4.33 Å
for the large cavities.
Hydrates in the category sII[9, 11, 13] are consisted of 136 water molecules which form two
types of cavities, 16 small and 8 large which shape a pentagonal dodecahedron (512)
and a pentagonal hexadecahedron (51264) respectively. The average cavity radius is
3.91 Å for the small and 4.73 Å for the large cavities.
The unit cell of structure H[9, 11, 13] is consisted of 34 water molecules. Three types of
cavities are formed- three small with the shape of pentagonal dodecahedron (512), two
medium (435663) and one large (51268). The average cavity radius is 3.91 Å for the small
cavity, 4.06 Å for the medium cavity and 5.71 Å for the large cavity. The formation of sH
types requires the existence of larger organic molecules.
Figure 2.1 Three hydrate unit crystals and constituent cavities[14]

Furthermore, in addition to the types I,II and H, two more types were referred from
Udachin and Ripmeester[15]. Despite the fact that no hydrocarbon molecules have been
found in them, their discovery sets the point of conducting new research studies
concerning the hydrates’ structures.
2.1.1 METHANE HYDRATES
Methane hydrates are consisted of methane molecules trapped within water molecules.
Methane and ethane crystallizes mainly in the sI structure. Type sI structure is depicted
in Figure 2.2. Thus, they are consisted of 46 water molecules. Two types of cavities are
formed - two small which have the shape of a pentagonal dodecahedron (512) and six
large which have the shape of a hexagonal truncated trapezohedron (51262). They are
crystallized in the cubic system. The hydration number ranges from 5.77 to 7.41.
NH=5.75 corresponds to complete hydration[16].
As it was mentioned above, methane and ethane crystallizes mainly in structure sI.
However, Subramanian et al indicated that, under certain conditions, the formation of
type sII hydrates is possible[17]. Raman and NMR spectroscopic measurements were
used to identify these structures.
Figure 2.2 (a) Linking five 512 polyhedra by two 51262 polyhedra to form structure I (b) Two-
dimensional view of face-sharing of 512 polyhedra to form 51264 polyhedra voids for structure II[9]

2.2 HYDRATE DEVELOPMENT
Hydrates are formed as tiny particles at the interface between water and hydrocarbon
phases. These coated water droplets begin to grow, if not removed rapidly, up to
agglomerate into larger masses hydrates (Figure 2.3).
Figure 2.3 Hydrate development
2.3 HYDRATE FORMATION
Under certain conditions, water molecules arrange themselves into structures, which
form three-dimensional (3D) polyhedra around the gases. These polyhedra then
combine to form specific crystalline lattices which entrap the guest molecule. For
systems containing both water and low molecular weight hydrocarbons, hydrates should
be taken into consideration in the phase diagram.
The formation of clathrate hydrates requires certain thermodynamical conditions which
include high pressure and low temperatures. Moreover, the formation is depended on
the stream’s composition as certain compounds affect the formation rate. Thus, the
analysis of the phase diagrams is required.
For a system which includes hydrocarbons in the gaseous phase the pressure-
temperature diagram (P-T diagram) is presented and analyzed (Figure 2.4).

Figure 2.4 Pressure/temperature diagram for methane + water in the hydrate region[18]
Figure 2.4, schematically represents a methane and H2O system at conditions around
hydrate region. The hydrate formation happens to the area at the left of all lines[19, 20].
Due to the fact that methane is the major component of natural gas, this diagram
provides adequate information about phase behavior for gas systems without a liquid
hydrocarbon phase.
Hydrate–methane–water systems involve the following phases[21]:
 Hydrate (H)
 Water-rich liquid (LW),
 Methane-rich vapor (VCH4 ) and
 Ice (I).
For equilibrium calculations, an equation of state (EoS) can describe all phases.
Q1 is the quadruple point which is the starting point for four 3-phase lines:
 The LW-H-V line, which has P/T conditions at which water and vapor form
hydrates, conditions of most interest in natural gas hydrate systems.
 The I-H-V line
 The I-LW-H line
 The I-LW-V line, which connects Q1 to the pure water triple point (I-LW-V) (273.16
K, 0.62 kPa) and denotes the transition between water and ice without hydrate

formation. Because Q1 is close to 273 K for all natural gas systems, the I-LW-V
line extends almost vertically below Q1 to 0.62 kPa.
Figure 2.5 describes systems[22] which may include: ethane + water, propane + water,
isobutane + water and water + carbon dioxide or hydrogen sulfide[23], which are both
common compounds of natural gas.
Figure 2.5 Gas + single condensate + water systems[18]
Hydrates will form at temperatures and pressures to the left of the region enclosed by
the three lines, whereas to the right of this region, hydrates are not possible. Upper
quadruple point Q2 often is approximated as the maximum temperature of hydrate
formation because line LW-H-LHC is approximately vertical because of the
incompressibility of those three phases.
2.4 HYDRATES EFFECTS IN GAS PIPELINES
The formation of gas hydrates can be a matter of vital importance for the industry as it is
related to blockage of the gas pipelines. Pipeline blockage can be either fluid related or
structure related. Problems related to infrastructure of the pipeline, which involves pipe
deformation, corrosion deposition and valve abnormal functioning, are interdepended to
structure-related blockages. However, these problems can be through careful and

regular inspections along with appropriate maintenance. On the contrary, fluid-related
blockages are considered to be more persevering and challenging to control. Fluid
related problems are associated with the formation and/or deposition of solids in the gas
pipeline. Gas hydrate deposition is considered as the most severe of these depositions.
In 1934 Hammerschmit observed that the formation of gas hydrates was responsible for
oil and gas transportation pipelines blockage. Light hydrocarbons such as methane,
ethane, propane and butane, along with the combinations of longer chain hydrocarbon
with methane, act as guest molecules. Furthermore, non-hydrocarbon molecules such
as N2, CO2 and H2S, which are more soluble to water are found in hydrates and are
known to promote hydrate formation.
Gas hydrates are responsible for many problems which include pipeline blockage,
jeopardizing the foundations of deep-water platforms and pipelines, plugging blowout
preventers during the production and causing tubing and casing collapse[6]. The effects
of hydrates in gas pipelines will be examined and analyzed within the current
assignment.
2.4.1 HYDRATE FORMATIONS AS INITIATORS OF NATURAL GAS PIPELINE
INTERNAL CORROSIONS
Hydrate formation is often responsible for various types of internal corrosion in gas
pipelines. Internal corrosion can be caused by either physical or chemical processes. It
is related to several parameters such as hydrate size, stage and the contact period[2].
Acidic gases, which include H2S, CO2 and Cl-, are components of hydrates which are
responsible for increasing the corrosion rate[24, 25]. Methane is also contributing to the
metal corrosion phenomena.[26, 27] Moreover, H2O is another agent responsible for
corrosion[28]. Interaction between the pipeline and the hydrates initiates internal
corrosion. In conjunction with rupturing, corrosion will further lead to gradual
degradation of the material and deterioration of its integrity. Eventually, corrosion can
lead to leakages and even to full bore rupture (FBR). As a result, the economic
repercussions decisively lead to political and environmental ramifications. Corollary to
the corrosion, the risk for the pipe’s integrity, can result to a replacement cost which
may reach $3 trillion[29].
2.4.1.1 Corrosion Initiation through Physical Processes
As it was mentioned, corrosion can be induced through physical processes. The
corrosion types caused by physical processes include cavitations, erosion, pitting,

galvanized and stress cracking corrosions[2].Throughout these stages, interaction
between hydrates phase and the pipeline walls initiates a type of corrosion described
below.
2.4.1.1.1 Cavitations Corrosion
In the first stage of the formation the existence of a semi-solid state, in which the
hydrate blocks are having liquid inside the cavities, is observed. During this stage the
hydrates are unstable. At areas of low pressure in the conveyed fluid are formed[30].
Cavitations occur when then liquid, moving with high speed, is subjected to a pressure
drop. Thus, vapor cavities are formed in the liquid existing in the hydrate. Pressure drop
eventuates at point of flow discontinuity, especially joints and bends. The vapor bubbles
are imploding, when subjected to higher pressure, and hitting the metal surface,
producing an intense shock wave which can remove the protective films. Henceforth,
corrosion is accelerated at the damaged surface.
2.4.1.1.2 Erosion corrosion
Throughout the time, the hydrates transmute from the semi-solid state into solid blocks.
These hydrate chips are moving with high velocity and are hitting the inner surface of
the pipeline walls, causing erosion. Erosion is defined as the destruction of a metal by
abrasion or attrition caused by the relative flow of fluid against the surface. On condition
that there is a constant bombardment of particles on the pipe wall surface, erosion-
corrosion occurs, causing the removal of the surface protective film or the metal oxide
from the surface, exposing the surface to erosion-corrosion (Figure 2.6) from the fluid
properties. Erosion-corrosion can be affected by many factors such as turbulence,
cavitation, impingement or galvanic effect and finally result to the pipeline’s rapid failure.
Moreover, at later stage, the hydrate chips agglomerate and form bigger blocks which
will require more energy to transport across the surface of the pipe-wall[30, 31].

2.4.1.2 Corrosion initiation by chemical/electrochemical processes
Natural gas’s composition often includes
amounts of CO2 and/or H2S gases in its
composition. Moreover, the transported
gas contains chloride ions (Cl-), originating
from the formation water, and sometimes
acetic acid (CH3COOH).
During the hydrate formation, the available
water reacts with these compounds,
producing acids that dissociate to
individually yield corrosive electrolysis
products (Equation 1):
Equation 1 :
During the hydrate solidification process, or when the solidified hydrate is melting
(during hydrate removal), there will be an interaction between the components of
equation (1) and the pipe's inner surface. Since these components are corrosive in
nature, corrosion reactions will be promoted over time through electrochemical
reactions to yield galvanic and electrolytic corrosions. The corrosion rate will be a
function of time, composition of the hydrate, pH and other thermodynamic properties
such as temperature, pressure, gas fugacity, etc.[25] Oxidation-reduction (or redox)
reaction takes place in electrochemical corrosions with oxidation taking place at anode
while reduction takes place at the cathode. However, spontaneous reactions occur in
galvanic (voltaic) cells (Figure 5) while non-spontaneous reactions occur in electrolytic
cells.
The anode of an electrolytic cell is positive (cathode is negative), therefore, the anode
attracts anions from the solution (Equation 2,3). However, the anode of a galvanic cell is
negatively charged, since the spontaneous oxidation at the anode is the source of the
cell's electrons or negative charge. The cathode of a galvanic cell is its positive terminal.
Figure 2.6: The "Horseshoe" type erosion-
corrosion damage in a copper pipeline[2]

Equation 2,3 :
2.5 SOLUTIONS TO THE HYDRATE FORMATION PROBLEMS
Hydrates formation can cause pipeline plugging due to their inclination of agglomerating
and attaching to the pipeline’s walls. Thus, their removal, which is strongly desirable,
can be achieved through temperature increase and/or pressure decrease. However,
even under these conditions, the hydrate decomposition remains a slow process.
Taking this into account, it is unambiguous that the key to confront the problem is
preventing the hydrate formation. The hydrate formation is based on three levels of
security, listed below:
1. Depressing the hydrate formation temperature. This can be achieved through
dehydration.
2. Adjusting the operating conditions in order to prevent the hydrate’s formation.
3. Formation can also prevented by the addition of chemicals that prolonging the
hydrate formation time using inhibitors[32].
2.5.1 CHEMICAL INJECTION
During the operation under certain conditions, where the hydrates could be formed, a
possible way to prevent the formation is changing the gas composition by injecting
chemical. Through chemical injection (a) the formation temperature can be reduced
and/or (b) the formation can be delayed. The injected chemical can generally be
classified into two types:
1. Thermodynamic inhibitors: The most widely used inhibitors of this type are
glycols and methanol. Although both glycol and methanol can be recovered the
recovery of ethanol is not preferred from the economical aspect due to the fact
that compared to glycols, more losses occur. The most commonly used glycols
are the monoethylene glycol (MEG) and the diethylene glycol (DEG). Triethylene
glycol (TEG) cannot be used for injection into a gas stream due to its very low
vapor pressure. MEG is preferred over DEG for application for applications
where the temperature is lower than -10 oC due to its high viscosity at low
temperatures[32].

2. Kinetic inhibitors: This type of chemicals is polymers consisted of carbon chains
and pendant groups. Partially formed hydrate cages are absorbed from the
polymer. The polymer is attached along the hydrate crystal surface and thus the
hydrate crystals are growing around the polymer therefore stabilizing the
hydrates as small particles in the aqueous phase. Field tests indicated that
kinetic inhibitors are effective up to ΔΤ= 20 οF, at concentrations varying from
550 to 3,000 ppm in the aqueous phase[33, 34].
In spite of the fact that it is not the best approach, this is one of the most publicized
techniques for handling the hydrate issue as it requires insignificant interruption to the
flow and is less meddlesome. The presence of compounds like H2S and SO2
contributes to the hydrate formation due to their high solubility to water. In the same
way, other chemicals are added to the natural gas transmission lines in order to cause
the inverse effect. These chemicals are altering the hydrate formation line of
equilibrium and, as a result, inhibiting the hydrate formation (Figure 2.7)
Many studies have been conducted over the years, concerning this issue. The first
studies on the hydrate inhibition were conducted by Hemmerschmidt in 1934[6]. In these
studies aqueous solutions such as lithium chloride, calcium chloride, zinc chloride, di-
ethylene glycol, methanol and glycerin were used. Furthermore, a large number of
similar studies were conducted from researchers such as Nakamaya and Hashimoto
(1980)[35], Davidson et al. (1981)[36], Makogon(1981)[37], Berecz and Balla-
Achs(1983)[38], Svatar and Fadnes (1992)[39], Kelland et al. (1995)[40]. Later studies have
been conducted on the mechanisms of gas hydrate inhibition by Sloan (1991)[41] ,
Lederhos et al.(1996)[42], Sloan (2003)[13]. Despite the fact that these studies have shed
Figure 2.7: Generic Hydrate Formation Curve. The properties of Petroleum Fluids[1]

light on the hydrate mechanisms, there is still a gap of knowledge and thus there is no
known hydrate inhibitor, until now, that can entirely eradicate the problem of hydrate
formation and deposition.
2.5.2 NATURAL GAS DEHYDRATION
Natural gas dehydration is a very important process if we consider the fact that gas
hydrates cannot be formed without the presence of water. Natural gas dehydration
leads to hydrate instability due to the fact that the water molecules (host molecules) are
inadequate to form enough lattices to host the gust molecules. This process is the only
process heretofore which is completely sufficient in preventing the formation of hydrates
in pipelines. A common misapprehension is that free water is the cause of hydrate
formation. However, from the thermodynamic perspective, the water dissolved in the
hydrocarbons is the cause of hydrate formation which happens at the hydrate-vapor
boundaries (Figure 2.8). Figure 2.8 presents the cooling curve (at a constant pressure)
of methane - water mixture consisted of 60 mol CH4 and 40 mol H2O.
Figure 2.8: Temperature-Composition diagram for Methane and Water.[18]
The years following after the discovery of hydrates existence in the pipelines,
Hammershmidt[6] and his colleagues published studies concerning gas dehydration with
the use of solid desiccants. The most widely used desiccants today are molecular
sieves, silica gel and alumina. The most significant of them are the molecular sieves,
which are crystalline solid materials with the property of adsorbing particular molecules
based upon size and polarity. They are preferred over silica gel due to the fact that it is
not damaged by liquid water and it has high water adsorption capacity. Three different

processes for lowering the dew point lowering were proposed by Deaton and Frost in
1946[43]: (a) Hygroscopic solution (b) Chemical adsorption (3) Physical adsorption.
However, only hygroscopic solution and physical adsorption methods have been
commercially applied. Due to the fact that in the second process the adsorbents cannot
be re-generated, it is not feasible and thus, not commercially used. The first process
involves lowering the water concentration by contacting the gas with tri-ethylene glycol
(TEG) which adsorbs water through hydrogen bonding. Detailed description of this
process can be found in Perry (1960)[44], Hall and Polderman (1960)[45], Loomer and
Welch (1961)[46] and Bucklin et al. (1985)[47]. Water removal is one of the most effective
approaches to prevent hydrate formation. However, it increases the overall cost of
transportation of natural gas. Furthermore it requires a technical process which may not
always be practically applicable For instance; in deep water production of natural gas,
hydrates formation occurs before one ever gets the natural gas to the surface. In such
cases the dehydration process cannot be implemented.
2.6 MAINTENANCE AND DETECTION OPERATIONS
2.6.1 OPTlMAL TRANSMISION OPERATIONS DESIGN
If we take into consideration the fact that inhibitors cannot completely eradicate hydrate
formation and deposition, it is obvious that the knowledge of hydrate forming conditions
have to be used in order to diminish the hydrate formation. Hydrates form at or below
the hydrate formation temperature for a given pressure and gas composition. Phase
diagram analysis is a tool used for the prediction of the lower and upper quadruple
points (Q1 and Q2) on the hydrate formation/dissociation line.
The first prediction method was proposed by Katz et al. in 1942[48] and is known as the
Ki-value Method. In 1945 a second method was introduced by Katz[48], known as the
Gas Gravity Method. Both of them allow the calculation of P-T equilibrium curves for
systems involving water (liquid phase), hydrate (solid phase) and natural gas (vapor
phase). These methods output initial estimates for the calculation and provide
qualitative understanding of the equilibrium. The second method provides more precise
results (Sloan 1990[49]). Moreover, a third method for the prediction of the equilibrium,
which is based on Statistical Mechanic, was introduced. This method is more
comprehensive and detailed and finally more accurate.

2.6.2 REGULAR PIPE INSPECTION AND PIGGING OPERATIONS
Pigging is a method according to which a device, known as “pig”, is inserted into a
pipeline. There is a variety of pig devises in the industry depending on their usage. Pigs
are used to remove solid deposits from the pipeline by scraping them off. Additionally,
there are types of pigs used to remove condensate and liquids from the natural gas
pipelines. These types of pigs are simple devises such as polyurethane foam plug to
push along liquids and condensates or include tungsten studs with abrasive wire
meshes on the outside to cut rust, scale or paraffin.
Furthermore, pigs are used for the pipeline inspection in order to detect corrosion
damage, leakages and blockages. Inspection pigs are highly complicated instruments.
.

3. CHAPTER 3
EXPERIMENTAL PROCEDURE
3.1 PREDICTION OF HYDRATE FORMATION USING COMPUTER SOFTWARE
As it was mentioned to the previous chapter, in order to provide the optimal strategy in
dealing with hydrate formation, it is of vital importance to have an understanding of the
conditions that cause hydrate formation. The most accurate predictions can be
conducted with the use of computer software. The basis of these programs is the
Equations of State (EoS).
In the current assignment the chemical simulations software Aspen Hysys® is used for
studying the formation conditions.
3.2 EXPERIMENTAL PROCEDURE
In order to simulate the streams and calculate the conditions, the Peng-Robinson
Equation of State (PR EoS) was used as it is the most applicable EoS in oil & gas
industry and is ideal for gas systems[50]. As a first step, three streams of natural gas with
different composition[51] were created:
Table 3.1 Stream Composition
Component Sweet Gas Sweet Gas + CO2 Sour Gas + CO2
Methane 0.926700 0.784000 0.842531
Ethane 0.052900 0.060000 0.031494
Propane 0.013800 0.036000 0.006699
i-Butane 0.001800 0.005000 0.002000
n-Butane 0.003400 0.019000 0.001900
n-Pentane 0.001400 - 0.003999
Nitrogen - 0.094000 0.002999
Hydrogen Sulfide - - 0.041792
Water - - -
Carbon Dioxide - 0.002000 0.066587

The initial conditions for each of these streams are set as following:
Table 3.2 Initial Conditions
Sweet Gas Sweet Gas + CO2 Sour Gas + CO2
Temperature (oC) 17 17 17
Pressure (bar) 80 80 80
Molar Flow (kmol) 1000 1000 1000
The Hydrate Formation Utility was used for each stream. It was observed that:
 “Sweet Gas” stream: Hydrates will not form under these conditions.
 “Sweet Gas + CO2” stream: Hydrates will form under these conditions.
 “Sour Gas + CO2” stream: Hydrates will form under these conditions.
Furthermore, the tool provides additional information towards the type of hydrates that
will form and indicates the Formation Temperature at Stream Pressure and Formation
Pressure at Stream Temperature. Thus, if pressure is kept constant the temperature
under which the hydrates are formed is indicated. Respectively, if the temperature is
kept constant, the tool indicates the pressure over which the formation occurs. For each
stream:
 “Sweet Gas” stream:
o If pressure is kept constant at 80 bar the hydrate formation occurs at
temperatures below 16.8943 oC.
o If pressure is kept constant at 17 oC the hydrate formation occurs at
pressures over 81.3558 bar.
Figure 3.1 Hydrate Formation utility Sweet Gas Design

Figure 3.2 Hydrate Formation Utility Sweet Gas Performance
 “Sweet Gas + CO2” stream:
o
Figure 3.3 Hydrate Formation Utility Sweet Gas + CO2 Design

Figure 3.4 Hydrate Formation Utility Sweet Gas + CO2 Performance
 “Sour Gas + CO2” stream:
Figure 3.5 Hydrate Formation Utility Sour Gas + CO2 Design

Figure 3.6 Hydrate Formation Utility Sour Gas + CO2 Performance
The range of conditions in which the hydrates are formed, can be shown in the following
diagrams.
Figure 3.7 Sweet Gas Envelope

Figure 3.8 Sweet Gas + CO2 Envelope
Figure 3.9 Sour Gas + CO2 Envelope

4. CHAPTER 4
CONCLUSIONS
Hydrate formation is proven to be a serious problem for the industry as it has negative
effects in gas transportation due to plugging and corrosion phenomena. Thus, the
industry has to handle great technical difficulties which raise the cost. Hydrate formation
is a function of pressure temperature and composition. Low temperatures and high
pressures increase the rate of hydrate formation. Moreover, hydrate formation is
affected from the composition. Compounds as CO2 and H2S increase the hydrate
formation due to the fact that their solubility in water is greater than the hydrocarbon’s
solubility. The problem can be handled by adjusting the operating conditions, by
dehydration or chemical injection.
It is obvious that the prediction of the hydrate formation is mater of vital importance. In
the experimental procedure, three natural gas streams with different composition were
examined.
Pressure was kept constant at 80 bar. For the sweet gas stream the formation occurs
under 16.9 oC. For the sweet gas stream which contains CO2 the formation occurs at
temperatures under 18.8 oC. Finally for the sour gas stream which also contains CO2,
the formation occurs at temperatures below 19.9 oC. It was observed that in the streams
which contained H2S and/or CO2 the formation occurred at higher temperatures for a
given pressure. As it was mentioned above, the existence of H2S and CO2 is
responsible for this.

5. ABBREVIATIONS – INITIALS
EoS Equation of State
FBR Full Bore Rupture
P-T Diagram Pressure-Temperature Diagram
Redox Reaction Reduction-Oxidation Reaction
MEG Monoethylene Glycol
DEG Diethylene Glycol
TEG Triethylene Glycol
PR EoS Peng-Robinson Equation of State

6. REFERENCES
1. McCain, W. D., The Property of Petroleum Fluids, PenWell Publishing, Tulsa,
Oklahoma, 1990.
2. Obanijesu, E. O., Pareek, V., Gubner, R. and Tade, M. O., Hydrate Formation and its
Influence on Natural Gas Pipeline Internal Corrosion Rate, Society of Petroleum
Engineers, 2011.
3. Chatti, I., Delahaye, A., Fournaison, L. and Petitet, J. P., Benefits and drawbacks of
clathrate hydrates: a review of their areas of interest, Energy Conversion and
Management, vol.46, no.9–10, 2005, pp. 1333-1343.
4. Jeffrey, G. A. and McMullan, R. K., The Clathrate Hydrates, Progress in Inorganic
Chemistry,ed., John Wiley & Sons, Inc., 1967, pp. 43-108.
5. Englezos, P., Clathrate hydrates, Industrial & Engineering Chemistry Research,
vol.32, no.7, 1993, pp. 1251-1274.
6. Hammerschmidt, E. G., Formation of Gas Hydrates in Natural Gas Transmission
Lines, Industrial & Engineering Chemistry, vol.26, no.8, 1934, pp. 851-855.
7. Yousif, M. H., The Kinetics of Hydrate Formation, Society of Petroleum Engineers,
1994.
8. Salam, K., Arinkoola, A., Araromi, D. and Ayansola, Y., Prediction of Hydrate
Formation Conditions in Gas Pipelines, International Journal of Engineering, vol.2, no.8,
2013, pp. 327-331.
9. Sloan Jr, E. D. and Koh, C., Clathrate hydrates of natural gases, CRC press, 2007.
10. Moridis, G. J., Numerical Studies of Gas Production From Methane Hydrates, 2003.
11. Sloan, E. D., Gas Hydrates: Review of Physical/Chemical Properties, Energy &
Fuels, vol.12, no.2, 1998, pp. 191-196.
12. Sloan, E. D., Jr., Natural Gas Hydrates, Journal of Petroleum Technology, vol.43,
no.12, 1991, pp. 1414-1417.
13. Sloan, E. D., Jr., Fundamental principles and applications of natural gas hydrates,
Nature, vol.426, no.6964, 2003, pp. 353-63.
14. Sloan, E. D., Bloys, J. B. and Engineers, S. o. P., Hydrate Engineering, Society of
Petroleum Engineers, 2000.
15. Udachin, K. A. and Ripmeester, J. A., A complex clathrate hydrate structure
showing bimodal guest hydration, Nature, vol.397, no.6718, 1999, pp. 420-423.
16. Dec, S. F., Bowler, K. E., Stadterman, L. L., Koh, C. A. and Sloan, E. D., Direct
Measure of the Hydration Number of Aqueous Methane, Journal of the American
Chemical Society, vol.128, no.2, 2005, pp. 414-415.
17. Subramanian, S., Kini, R. A., Dec, S. F. and Sloan Jr, E. D., Evidence of structure II
hydrate formation from methane+ethane mixtures, Chemical Engineering Science,
vol.55, no.11, 2000, pp. 1981-1999.
18. Sloan, E. D., Jr., Clathrate Hydrates of Natural Gases, Revised and Expanded, CRC
Press, 1998.

19. Sloan, E. D., Khoury, F. M. and Kobayashi, R., Water Content of Methane Gas in
Equilibrium with Hydrates, Industrial & Engineering Chemistry Fundamentals, vol.15,
no.4, 1976, pp. 318-323.
20. Lasich, M., Mohammadi, A. H., Bolton, K., Vrabec, J. and Ramjugernath, D., Phase
equilibria of methane clathrate hydrates from Grand Canonical Monte Carlo simulations,
Fluid Phase Equilibria, vol.369, no.0, 2014, pp. 47-54.
21. Yang, S. O., Cho, S. H., Lee, H. and Lee, C. S., Measurement and prediction of
phase equilibria for water + methane in hydrate forming conditions, Fluid Phase
Equilibria, vol.185, no.1–2, 2001, pp. 53-63.
22. Gernert, J., Jäger, A. and Span, R., Calculation of phase equilibria for multi-
component mixtures using highly accurate Helmholtz energy equations of state, Fluid
Phase Equilibria, vol.375, no.0, 2014, pp. 209-218.
23. Coquelet, C., Valtz, A., Stringari, P., Popovic, M., Richon, D. and Mougin, P., Phase
equilibrium data for the hydrogen sulphide+methane system at temperatures from 186
to 313K and pressures up to about 14MPa, Fluid Phase Equilibria, vol.383, no.0, 2014,
pp. 94-99.
24. Norsork Standard, CO2 Corrosion Rate Calculation Model, Norwegian
Technological Standards Institute Oscarsgt., Majorstural, Norway, 2005, p.20.
25. Obanijesu, E. O. and Macaulay, S. R. A., West African Gas Pipeline (WAGP)
Project: Associated Problems and Possible Remedies, Appropriate Technologies for
Environmental Protection in the Developing World,ed., E. Yanful,ed., Springer
Netherlands, ch.12, 2009, pp. 101-112.
26. Liang, Y., Shuichi, I., Yomei, Y. and Kunihiko, W., High Temperature Corrosion of
Gas Turbine Blade Material in Methane Gas Combustion Environment with the Injection
of SO2/NaCl, NACE International, p.1-11.
27. McKee et. al., Carbon Deposition and the Role of Reducing Agents in Hot-Corrosion
Processes, Chemistry and Material Science, 2007, pp. 1877-1885.
28. Kritzer, P., Corrosion in high-temperature and supercritical water and aqueous
solutions: a review, The Journal of Supercritical Fluids, vol.29, no.1–2, 2004, pp. 1-29.
29. Fingerhut, M., and Westlake, Pipeline fitness for purpose certification, 29/12/2014;
http://www.corrosion-club.com/pipelines.htm.
30. Roberge, P. R., "Corrosion Engineering: Principle and Practise, 1st-ed., The
McGraw-Hill Companies Inc., New York, 2008.
31. Brown, G. J., Erosion prediction in slurry pipeline tee-junctions, Applied
Mathematical Modelling, vol.26, no.2, 2002, pp. 155-170.
32. Gao, S., Investigation of Interactions between Gas Hydrates and Several Other
Flow Assurance Elements, Energy & Fuels, vol.22, no.5, 2008, pp. 3150-3153.
33. Fu, S. B., Cenegy, L. M. and Neff, C. S., A Summary of Successful Field
Applications of A Kinetic Hydrate Inhibitor, Society of Petroleum Engineers.
34. PetroWiki.org, Preventing formation of hydrate plugs, 28/12;
http://petrowiki.org/Preventing_formation_of_hydrate_plugs.
35. Nakayama, H. and Hashimoto, M., Bulletin of the Chemical Society of Japan, 1980,
p. 2427.

36. Davidson, D. W., Gough, S. R., Ripmeester, J. A. and Nakayama, H., The Effect of
Methanol on the Stability of Clathrate Hydrates, Can. J. Chem., vol.59, 1981, p. 2587.
37. Makogon, Y. F., Hydrates of Natural Gas,, Moscow, Nedra, Isadatelstro, 1921.
38. Berecz, E. and Balla Achs, M., Gas hydrates, Elsevier, Amsterdam, 1983.
39. Svatas, T. M. and Fadnes, F. H., Proceedings Intl. Oshore and Polar Eng. Conf.
614, Proc., June 1992.
40. Kelland, M. A., Svartaas, T. M. and Dybvik, L., New Generation of Gas Hydrate
Inhibitors, 70th SPE Annual Techinical Conference and Exibition,, 1995, p.529-537.
41. Sloan, B., Natural Gas Hydrates, Journal of Petroleum Technology vol.43, 1991, pp.
1414-1417.
42. Lederhos, J. P., Long, J. P., Sum, A., Christiansen, R. L. and Sloan, E. D., Effective
Kinetic Inhibitors for Natural Gas Hydrates, Chemical Engineering Science, vol.51, no.8,
1996, p. 1221.
43. Deaton, W. M. and Frost, E. M., Gas Hydrates and Their Relation to the Operation
of NaturalGas Pipelines, U.S. Bureau of Mines Monograph, 1946.
44. Perry, C. R., Oil and Gas Journal, vol.58, 71, 1960.
45. Hall, G. D. and Polderman, L. D., Design and operating tips for ethanolamine gas
scrubbing systems, Chemical Engineering Progress, vol.56, no.10, 1960, pp. 22-58.
46. Loomer, J. A. and Welch, J. W., Some Critical Aspects of Designing for High
Dewpoint Depression with Glycols, Proc. Proc. Gas Cond. Conf., 1961.
47. Bucklin, R. W., Toy, K. G. and Won, K. W., Hydrate Control of Natural Gas Under
Arctic Conditions Using TEG, Proc. Proc. Gas Conditioning Conference, 1985.
48. Curson, D. B. and Katz, D. L., Natural Gas Hydrates, vol.146, 1942, p. 150.
49. Sloan, E. D., Clathrate Hydrates of Natural Gases, Marcel Dekker, 1990.
50. Ashour, I., Al-Rawahi, N., Fatemi, A. and Vakili-Nezhaad, G., Applications of
Equations of State in the Oil and Gas Industry, 2011.
51. Gas Processors Suppliers Association Engineering Data book, 12th Edition,ed.,
ch.20, 2004, pp. 1-15.

Hydrate formation in gas pipelines

Recomendados

Recomendados

Más contenido relacionado

La actualidad más candente

La actualidad más candente (20)

Similar a Hydrate formation in gas pipelines

Similar a Hydrate formation in gas pipelines (20)

Más de Fotios N. Zachopoulos

Más de Fotios N. Zachopoulos (10)

Último

Último (20)

Hydrate formation in gas pipelines