Dissociation Pressure of Natural Gas Hydrate - NTNU

Dissociation Pressure of Natural Gas Hydrate
TPG4510 Petroleum Production Specialization Project
by
Torbjørn Gjellesvik
Trondheim
December 2011

Acknowledgements
This project could not have been completed had it not been for the help and input of
others. I have encountered issues both where I have been in doubt regarding what to do
and how to do it. Without the help of these people I would probably have struggled
immensely to complete the project in time.
First, I would like to thank Professor Jon Steinar Gudmundsson for all his help in finding
a suitable problem description and guidance along the way. Many of the resources I have
used could not have been accessed without his help and some are crucial to the final
result of this work. I would also like to thank for quick responses to any questions I
might have had and good advice.
Second, I would like to thank my fellow students, especially within petroleum
production, for their input, thoughts and suggestions. The communication I have had
with them has been motivational and a great help throughout the semester.
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Abstract
The dissociation pressure and temperature of natural gas determines when hydrate
formation can take place. Initial formation of hydrate takes place at slightly higher
pressures and lower temperatures due to a small amount of energy required for the first
crystallization. The dissociation pressure is very valuable in planning steps to mitigate
hydrate formation in oil and gas production.
Several methods exist for calculating the dissociation pressure of natural gas hydrate,
ranging from rigorous computer methods to simpler hand calculation methods. In this
project, a comparison between computer models and hand calculation methods has
been performed. Aspen HYSYS has been used as an example of available computer
methods, whereas the correlation presented by Østergaard et al. (2000) and an updated
version of the Makogon correlation (1981) has been selected as hand calculation
methods. The ground for comparison is made by assuming HYSYS to be a reference
point and investigating how well the hand calculation models correspond under
different circumstances when applied to three typical mixtures of natural gas.
Also, the effect of certain parameters on the dissociation pressure has been investigated,
as well as a brief overview of currently used inhibitors in the industry. By varying the
contents of N2, CO2 and H2S the results have been presented graphically.
Results show that the Makogon correlation corresponds surprisingly well with results
from HYSYS in many situations. The effects of N2 and CO2 have been identified by the
Østergaard et al. correlation. Calculations performed by increasing H2S content also
shows that it has a severe negative effect on the dissociation pressure of natural gas
hydrate.
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Table of Contents
ACKNOWLEDGEMENTS.................................................................................................................................II
ABSTRACT.......................................................................................................................................................III
TABLE OF CONTENTS.................................................................................................................................. IV
LIST OF TABLES ..............................................................................................................................................V
LIST OF FIGURES.............................................................................................................................................V
INTRODUCTION ..............................................................................................................................................1
PROJECT DESCRIPTION...................................................................................................................................................... 1
NATURAL GAS..................................................................................................................................................3
PROPERTIES......................................................................................................................................................................... 3
ECONOMIC AND ENVIRONMENTAL IMPORTANCE......................................................................................................... 4
NATURAL GAS HYDRATES...........................................................................................................................6
PROPERTIES......................................................................................................................................................................... 6
NATURAL OCCURRENCE.................................................................................................................................................... 7
HYDRATE INHIBITION........................................................................................................................................................ 8
CHEMICAL POTENTIAL ...................................................................................................................................................... 8
THE HAMMERSCHMIDT EQUATION................................................................................................................................. 9
DISSOCIATION PRESSURE ........................................................................................................................ 10
INFLUENCING PARAMETERS.......................................................................................................................................... 10
FIELDS AND GAS COMPOSITIONS........................................................................................................... 12
SHTOKMAN ....................................................................................................................................................................... 12
ORMEN LANGE ................................................................................................................................................................. 13
GENERIC ............................................................................................................................................................................ 14
CALCULATION METHODS ......................................................................................................................... 15
HYSYS............................................................................................................................................................................... 15
DERIVATION OF THE PENG-­‐ROBINSON EQUATION OF STATE................................................................................. 16
MAKOGON, ELGIBALY & ELKAMEL............................................................................................................................... 18
THE BAILLE-­‐WICHERT METHOD ................................................................................................................................. 21
RESULTS ......................................................................................................................................................... 22
MODEL COMPARISONS.................................................................................................................................................... 22
EFFECT OF H 2S AND MODEL APPLICABILITY .............................................................................................................. 24
DISCUSSION ................................................................................................................................................... 28
CONCLUSION ................................................................................................................................................. 32
REFERENCES ................................................................................................................................................. 33
APPENDIX A................................................................................................................................................... 36
MODEL COMPARISONS.................................................................................................................................................... 36
ØSTERGAARD ET AL. CORRECTION FOR N 2 AND CO 2 ................................................................................................ 37
EFFECT OF H 2S – HYSYS............................................................................................................................................... 38
EFFECT OF H 2S – ØSTERGAARD ET AL. ....................................................................................................................... 39
EFFECT OF H 2S – MAKOGON ET AL.............................................................................................................................. 40
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List of Tables
Table 1:
Table 2:
Table 3:
Table 4:
Table 5:
Coefficients for the Hammerschmidt equation, Ci.
Ci-­‐constants used in the Østergaard et al. correlation.
α-­‐constants used in the Østergaard et al. correlation.
Field compositions.
Inhibitor base price.
List of Figures
Figure 1: Overview of the biggest gas producing countries.
Figure 2: Estimated future consumption of energy sources.
Figure 3: Model comparison – Ormen Lange
Figure 4: N2 and CO2 correction using the Østergaard et al. correlation -­‐ Shtokman
Figure 5: Effect of H2S content. HYSYS results – Ormen Lange
Figure 6: Effect of H2S content. Makogon et al. – Ormen Lange
Figure 7: Effect of H2S content. Østergaard et al. – Ormen Lange
Figure 8: Inhibitor vapor pressures.
Figure A1: Model Comparison -­‐ Shtokman
Figure A2: Model Comparison -­‐ Generic
Figure A3: Model Comparison – Ormen Lange
Figure A4: Østergaard Dissociation Curves – Shtokman
Figure A5: Østergaard Dissociation Curves – Ormen Lange
Figure A6: HYSYS Effect of H2S -­‐ Shtokman
Figure A7: HYSYS Effect of H2S -­‐ Generic
Figure A8: HYSYS Effect of H2S – Ormen Lange
Figure A9: Østergaard et al. Effect of H2S -­‐ Shtokman
Figure A10: Østergaard et al. Effect of H2S -­‐ Generic
Figure A11: Østergaard et al. Effect of H2S – Ormen Lange
Figure A12: Makogon et al. Effect of H2S -­‐ Shtokman
Figure A13: Makogon et al. Effect of H2S – Generic
Figure A14: Makogon et al. Effect of H2S – Ormen Lange
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Introduction
Natural gas has a great upside for future applications. Faced with a growing worldwide
demand for energy, while at the same time also faced with the issues of global warming,
the consumption of natural gas is expected to grow in the future. The simple answer is
because of two things: First, the worldwide reserves of natural gas exceed hose of crude
oil by approximately 10%. Second, burning of natural gas as a source of energy emits
less CO2 than alternate fossil fuels by 20-­‐40% per unit of energy consumed, making it
more environmentally friendly (IEA, 2011). Therefore, as a substitute for coal and crude
oil, natural gas represents a significant contribution in reducing climate gas emissions to
the atmosphere. As governments strive to reduce emissions by as much as possible, it is
easy to understand why the natural gas consumption is expected to grow.
The aim of this project is first and foremost to try and answer the questions put forward
in the problem description. As the title aptly describes, the subject of the project is the
dissociation pressure of natural gas hydrate. Hydrates are solids that are commonly
encountered in the transportation of natural gas. They are very unfavorable as they can
do severe damage to pipelines and equipment, and they are very hard to avoid because
hydrate formation conditions often lie within the operating region of oil and gas
production.
Project Description
“Oil and gas cannot be produced through offshore pipelines without the prevention of
hydrate formation. Hydrate forms due to high pressure and low temperature, typically 100
bara and 20°C. The exact hydrate formation point depends on the composition of the fluids
involved; gas composition and water/brine composition.
Computer and analytical methods have been developed to predict the dissociation pressure
of natural gas hydrate. The dissociation pressure can be used to determine how much
antifreeze needs to be added to prevent the formation of hydrate. The purpose of the
present project is to investigate how the various parameters affect the dissociation
pressure of hydrate, including gas composition, presence of acid gases and the salt content
of the liquid water phase. The HYSYS code can be used and an attempt should be made to
find out what theoretical method is used there. Available analytical methods should be
1

used and compared to the results from HYSYS. Try to answer the question whether a
mixture of antifreeze chemicals offers any advantage in preventing the formation of
hydrate” (Gudmundsson, 2011).
The dissociation pressure is the required pressure for hydrates to start dissolving. For
that reason, it is very valuable information to have in order to plan for avoidance and
inhibition of hydrates. Not only does the dissociation pressure provide information
about what it takes to dissolve already formed hydrates, but in reversing the point of
view, it also determines the conditions where hydrates continue to form. Conditions for
initial hydrate formation tends to be at lower temperatures and pressures than the
dissociation pressure. This is because a small amount of energy is required for the first
hydrate to crystallize. As soon as hydrate has formed, the dissociation pressure
determines the continued formation. This clarifies why knowledge about the conditions
for dissolving already formed deposits is important in order to avoid them in the first
place.
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Natural Gas
Properties
To understand the concept of natural gas hydrates, one needs to have an idea of what
natural gas really is and its application. This way, it is much easier to comprehend the
safety, technical and economical challenges that hydrate formation represents in the
petroleum industry.
Natural gas occurs naturally and is often associated with production of crude oil. It is
created through decomposition of organic material under high pressures and
temperatures. Furthermore, fuel is its biggest application, whether as fuel for means of
transportation or as a source of electricity for domestic heating and other appliances.
The main components are the light hydrocarbon components: Methane (CH4), ethane
(C2H6), propane (C3H6), n-­‐ and i-­‐butanes (C4H10) and n-­‐ and i-­‐pentanes (C5H12). Other
heavier hydrocarbon components are also present in typical natural gasses, but they are
not typical and often not in significant amounts. Non-­‐hydrocarbon components often
present in natural gas include nitrogen (N2), carbon dioxide (CO2) and hydrogen sulfide
(H2S) (Carroll, 2003). Moreover, natural gas is usually saturated with water vapor, and
this is when the hydrate warning signs start flashing. Water is a requirement for
hydrates to from and is further explained in the next section, which describes the
properties of natural gas hydrate.
A typical natural gas is significantly richer in methane than the other components.
Methane content often lies in the region of 90%, depending on its origin. Non-­‐associated
gas, which is gas normally present in the reservoir, tends to have higher methane
content (90+%) than associated gas. Associated gas has vaporized, or flashed, out of
solution from crude oil. This gas tends to have less than 90% methane content
(Gudmundsson, 2011). According to the amount of methane, the ethane content in
natural gas lies around 0-­‐10%, propane from 0-­‐5%, while the heavier components
gradually decrease further. Non-­‐hydrocarbon components tend to amount to 0-­‐5% of
the gas, with H2S content possibly reaching as high as 15%. Obviously, natural gas
encompasses a very wide variety of compositions and it might be easier to look at it as
gas produced for fuel and power generation purposes.
3

With fuel being the number one application of natural gas, the non-­‐hydrocarbon gasses
are considered unfavorable. They do not have any heating value, rendering them useless
as fuels (Carroll, 2003). They are also rarely considered very valuable to other ends,
although there are some exceptions. CO2 can, assuming the appropriate infrastructure,
be re-­‐injected and used as means to build pressure in reservoir. H2S also serves some
purpose in the manufacturing of artificial fertilizer or sulfur, but its value is very
dependant on demand (www.snl.no, 2003).
Economic and Environmental Importance
The present estimated reserves of natural gas exceed those of crude oil by
approximately 10%, in terms of energy content. The vast majority of reserves come from
Russia, Iran and Qatar and amount to over half of the total world reserves. Norway’s gas
reserves are about 4% of the total world reserves. The price of natural gas is calculated
from energy content, not by volume. The most common unit is dollars per million British
thermal units ($/MMBtu). One British thermal unit is the amount of energy required to
heat one pound of liquid water from 60 F to 61 F under atmospheric pressure (1 atm)
(www.snl.no, 2011).
Figure 1: Overview of the biggest gas producing countries.
The natural gas price is somewhat less volatile than that of crude oil. This is because the
production is easier to regulate, making it more adaptable to current demand. However,
it tends to follow the same trends as the oil price.
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There are several advantages with using gas compared to other fossil fuels, so there’s a
significant upside to future applications. The perhaps biggest positive of natural gas is
that it emits less CO2 than other fuels. When compared to coal and oil, natural gas emits
40% and 20% less CO2 per unit of energy used. In power generation, modern gas
turbines produce about half of what current coal-­‐fired plants do (IEA World Energy
Outlook, 2011).
Transportation of gas is easier and much more efficient in terms of volumes across
distance. However, the present infrastructure needs to be improved in order to reach
more people. Governments are constantly trying to find more environmentally friendly
and sustainable sources of energy. Germany is a good example. By 2022, they’ve moved
to decommission all of their nuclear power plants, although the grounds for the decision
are from a safety perspective. The consequences of nuclear power generation became
painfully obvious in 1986 by the Tschernobyl meltdown, and more recently by the
Fukushima incident in Japan, January 2011, which is said to spark Germany’s sudden act
towards decommission. Due to the many advantages over other fossil fuels, natural gas
is a commodity expected to be consumed more and more in the future (See Fig. X). In
order to reach EU’ goal of reducing total CO2 emissions by 20% by the year 2020, the use
of certain fossil fuels has to decrease. Moving away from coal and crude oil, natural gas
is a great substitute, reducing emissions quite substantially and being easier to
transport.
An interesting trend is that national gas consumption seems to follow the GPD of said
nation one-­‐to-­‐one. Hence, for a 1% increase in GDP there’s also a 1% increase in gas
consumption. Especially for the BRIC-­‐countries (Brazil, Russia, India and China), the
population is becoming increasingly rich, leading more people to afford higher living
standards. Higher energy consumption follows as a direct result and the demand
increases. As long as the proper infrastructure is in place, gas can be an extremely
valuable resource to countries in rapid growth as large supplies will be readily available
at a low cost. Therefore, the IEA assumes that out of the currently available energy
sources, gas consumption will increase the most in the years to come (IEA World Energy
Outlook 2011).
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Figure 2: Estimated future consumption of energy sources.
Natural Gas Hydrates
Properties
A hydrate is a compound that resembles ice and consists of water and a second
substance. This second substance can be a lot of things, but in natural gas hydrate, they
are the light hydrocarbon components methane, ethane, propane and butane, and non-­hydrocarbons
such as CO2 and H2S. Hydrate made up of these components and that
forms in natural gas is the focus of this project. Hydrate is not ice, but has a very similar
physical appearance. Whereas ice is crystalline frozen water that only occurs at
temperatures of 0°C or less (assuming atmospheric pressure), hydrates occur at
temperatures above the freezing point of water and at very high pressures (0-­‐25°C and
≈100 bara). They also require the presence of these second substances, or host
molecules, to form. The host molecules are smaller than the water molecules and small
enough to fit inside crystalline structures formed by the water molecules. (The cages
that are typical to hydrates are often referred to as “clathrates”. The word “clathrate”
comes from the Latin “clathratus”, meaning “lattice bars”.)
When the temperature and pressure conditions favor the formation of hydrate the water
molecules start aligning in a certain pattern. The host molecule stabilizes the already
organized water molecules and is what causes them to crystallize. The crystals
6

effectively form a cage, held together by hydrogen bonding, trapping the host molecules.
A hydrogen bond is the attractive intermolecular force between the polar water
molecules. The two positively charged hydrogen atoms of a water molecule attract the
negative oxygen atoms from other molecules, forming an intermolecular bond. In a
pipeline, as soon as a hydrate crystal is formed, they will continue to travel along with
the flow. This isn’t as problematic, so long as the crystals are small. Obviously, larger
crystals can damage pipeline equipment such as valves and pumps and needs to be
accounted for. Irregularities and equipment installed within the pipeline make good
nucleation points and cause the hydrates to deposit (Gudmundsson, 2011).
“Good nucleation sites for hydrate formation include an imperfection in the pipeline, a
weld spot, or a pipeline fitting (elbow, tee, valve, etc.) Silt, scale, dirt and sand all make
good nucleation sites as well” (Carroll, 2003).
After nucleation is when the hydrate issues start to become major. Once hydrates have
deposited and the conditions still favor continued formation, the deposits grow like a
rolling ball of snow. This is very problematic as the deposits become large. Ultimately, it
may lead to reduced pipe flow (due to reduced cross-­‐sectional flow area), damaged
equipment and possibly plugged pipelines. Thus, issues caused by hydrates represent a
safety hazard and often require costly and time-­‐consuming maintenance operations.
Natural Occurrence
A peculiar fact about natural gas hydrates is that they actually pose as a potential source
of energy. They occur naturally where the pressure and temperature conditions are
right, often below sea level, but also onshore in permafrost regions. The crystal
structure of hydrates traps the host molecules within a cage. There is no connection
between the water molecules and the trapped host molecule, sparking the thought of
extracting the hydrocarbon components from within their hydrate cages. Naturally
occurring hydrates as a source of fossil fuel has still not prevailed as a sustainable
source of energy. This is because of the environmental and geological effects of
extracting these hydrates. Methane, which is the most common hydrocarbon found in
hydrates is a powerful greenhouse gas and would have a severe effect on the
environment. Removal of the naturally occurring hydrates is also hazardous because it
7

affects the geological stability and could lead to subsea landslides etc. (Kvenvolden,
1993).
Hydrate Inhibition
A lot of resources are spent towards predicting and preventing hydrate formation in the
petroleum industry. Pipelines are commonly insulated over short distances to avoid
severe temperature drops. Over longer pipeline intervals, large amounts of chemical
inhibitors are injected to alter the thermodynamic properties of the fluid flow, causing
the hydrate forming conditions to lie outside of the operating conditions. Obviously, to
be able to safely predict the hydrate formation offers many advantages.
Chemical Potential
The change in chemical potential (µ) over the course of the chemical reaction of hydrate
formation is very interesting as it introduces a measure towards hydrate inhibition. A
simple reaction for hydrate formation can be described as follows:
H 2
O( l) + Gas ↔ H 2
O( hyd)
Changing the reaction with respect to chemical potential and expressing it algebraically
gives:
Δµ = µ hyd
H2 O
l
− µ H2 O
− µ gas
where µ hyd H20, µ l H20 and µgas is the chemical potential of hydrate, liquid water and gas,
respectively. The chemical potential can be explained as the measure of a substance’s
contribution to the function’s rate of change (Baierlein, 2001). The above reaction will
only happen as long as Δµ < 0. However, the chemical potential of gas and hydrate
cannot be changed, thus the chemical potential of liquid water is the only thing that can
be altered. The expression for the chemical potential of water can be described as:
l
µ H2 O
= µ H2 O
+ RT ln( a H2 O ) = µ H2 O
+ RT ln( γ x H2 O H 2 O )
where µ°H2O is the standard Gibbs free energy, often expressed as G°(T), R is the
universal gas constant (8,314 J/K·mol), T is temperature (K), a is the activity of the
substance, γ is specific gravity and x the molar fraction of water. Remembering that the
8

eaction only goes if Δµ < 0, by reducing the mole fraction of water the chemical reaction
will shift to the left and thereby prevent hydrate formation. This introduces water
dilution as a means of hydrate inhibition, which is described (Sandengen, 2011 &
Skogestad, 2009).
Commonly used inhibitors in the petroleum industry today include: Methanol, ethanol,
monoethylene glycol (MEG), diethylene glycol (DEG) and triethylene glycol (TEG). In
fact, salt may also be used as an inhibitor as it too lowers the hydrate formation
temperature. Temperature depression is the common denominator for all the chemical
inhibitors. Unfortunately, injection of chemical inhibitors is not very effective, at least
not economically speaking. Large quantities are often required causing the economics of
inhibition to be considered.
The Hammerschmidt Equation
There exist simple methods to figure out the quantity of chemical inhibitor needed in
order to obtain a certain temperature depression. The Hammerschmidt equation is a
widely used example of such a method. A prerequisite for the equation is to have
information about the hydrate dissociation for the given mixture of fluid. This is because
the Hammerschmidt equation only computes the temperature depression by injecting a
certain amount of inhibitor. Assuming knowledge about the hydrate dissociation
conditions, the equation is used to determine the quantity of inhibitor needed. The
Hammerschmidt equation:
ΔT =
M i
C i
W i
( )
100 − W i
where ΔT is the temperature depression caused by the inhibitor, Ci is a constant
depending on type of inhibitor (see Table 1), Mi is the molecular weight of the inhibitor
and Wi is the weight fraction of inhibitor. Turning the equation around, the
Hammerschmidt equation becomes:
W i
=
100M i ΔT
C i
+ M i
ΔT ( )
Hence, as long as the required temperature depression is known, the weight fraction or
inhibitor can easily be obtained.
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Table 1: Coefficients for the Hammerschmidt equation, Ci.
Dissociation Pressure
The dissociation pressure of natural gas hydrate is the pressure at which the hydrates
first start to dissolve. Knowledge about when hydrates dissolve is used to predict when
hydrates can be expected to form. This is somewhat of an oxymoron but still the most
accurate way of identifying when the actual formation starts. In order for hydrates to
form, the natural gas mixture needs to be supersaturated with water, meaning it
contains more water vapor than actually possible to solve in the gas mixture. This is the
most important condition needed for continued formation. However, if no hydrates are
already present in the mixture, the conditions need to favor nucleation or crystallization.
This generally means additional cooling, as hydrate forms at low temperatures.
If no hydrates have crystallized at the initial conditions, the first record of hydrates
would occur under the nucleation or crystallization conditions. Under these conditions,
the temperature would be lower than what is required for already formed hydrate
deposits to grow (Gudmundsson, 2011). So, consider the case where hydrates are
already present. Dissociation will only happen as soon as the natural gas mixture is
undersaturated with water. The temperature at which the hydrates start to dissolve is in
fact the first point where hydrates can safely be expected.
Influencing Parameters
There are many parameters that affect the specific dissociation pressures and
temperatures. Especially gas composition, and thereby gas gravity, influences
temperatures and pressures needed to dissolve natural gas hydrate. For the
10

hydrocarbon hydrate formers, the lighter the component, the higher the dissociation
pressure tends to be. Of the non-­‐hydrocarbon formers commonly present in natural gas,
N2 exhibits a higher dissociation pressure than CO2 and H2S, respectively (Carroll, 2003).
Both CO2 and H2S are Type 1 hydrate formers and regarded as acid components. N2 is a
Type 2 former and an inert component, meaning it is chemically inactive. Therefore,
increasing the amount of acid components causes the mixture to contain more hydrate
formers, thus increasing the potential for hydrate formation. Conversely, high contents
of non-­‐hydrate formers will make the mixture less prone to hydrate formation. The fact
that the non-­‐formers in natural gas tend to be the heavier hydrocarbons further reduce
the possibility of hydrate formation because of their tendency to liquefy at typical
hydrate forming conditions for natural gas. Although liquid components do not
theoretically exclude the possibility of hydrates forming (liquid phase hydrate formation
is entirely plausible), the conditions for such hydrates to form are different from than
the conditions for gas hydrates.
Salinity has also shown to influence the dissociation temperature of hydrates. For pure
water, salinity will stretch the temperature scale in both ends, meaning it will freeze at
lower temperatures than usual, and boil at temperatures higher than usual. In the paper
presented by Mohammadi & Richon (2007), a similar approach to the problem is used to
investigate the effects of salinity on the hydrate dissociation temperature, and thus,
dissociation pressure.
Salt lowers the hydrate formation temperature and following correlation applies for
saline water temperature correction:
T = T 0
− 2,65ΔT b
T is the hydrate dissociation temperature, T0 is the dissociation temperature for distilled
water and ∆Tb is the boiling point elevation of the aqueous solution for distilled water
under atmospheric pressure. The authors of the paper also recommend the Østergaard
et al. correlation, which is described later, as a suitable way of obtaining the dissociation
temperature in the presence of distilled water (Mohammadi & Richon, 2007). Due to
lack of data on boiling point elevations due to salinity, the effect of salinity is simply
described in this project without case examples or simulations of any kind.
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Fields and Gas Compositions
Shtokman
The Shtokman Field is a significant gas field by world comparison and lies on the
Russian Arctic Shelf 555 km northeast of Murmansk. Its reserves are estimated to be
somewhere in the region of 3,8 trillion cubic meters and about 53,4 million tons of gas
condensate. The field is actually somewhat larger (3,9 trillion cubic meters gas and 56
million tons of condensate), but by reserves it is referred to the volumes Gazprom,
which is the field operator, can reach within the area they have a license.
Gazprom owns the license to operate the Shtokman field through one of its subsidiaries.
The project of developing and operating the field is divided into three phases. In Phase 1,
other companies also take part in the field development. Gazprom, Total E&P and Statoil
(formerly StatoilHydro) are stakeholders in Shtokman Development AG, which is the
company in charge of developing Phase 1 of the Shtokman field. Gazprom, Total E&P and
Statoil hold 51%, 25% and 24% of the stakes in the company, respectively.
Phase 1 encompasses all the preparations from drilling to production, and the initial
field development. As of the first quarter of 2011, the two required drilling rigs are
completed. A total of six subsea templates, each with four well slots, have already been
planned for.
The Shtokman field will be operated utilizing floating production units (FPSOs/FPUs).
The FPUs are connected to the subsea templates via flexible risers. The produced
volumes are processed aboard the FPUs before they are sent back to the seafloor and
into pipelines. The pipelines will carry the gas and condensate onshore over the vast
distance of 555 km to the planned gas treatment unit (GTU) in Zavalishina bay in
northwestern Russia (Gazprom, 2011).
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Ormen Lange
Ormen Lange is the second largest gas field in Norway, only beaten by the Troll field, and
the third largest in Europe. It is located offshore in the Møre basin about 120 km
northwest of Kristiansund in the southern part of the Norwegian Sea. It can be classified
as a deepwater field as the water depths lie between 800 – 1100 meters. The field was
discovered in 1997, and put in production on the 13 th of September 2007. Fairly new
technology is used in the production of the field. As of October 27 2011, there are 16
producing wells currently in operation connected to 3 subsea templates. Planned
development of the Ormen Lange field accounts suggests that a total of 24 producing
wells are to be drilled. This number is subject to change as the field is developed (Norske
Shell, 2011).
Norske Shell is the field operator but a number of entities are licensees in the field.
These include Shell (17%), ExxonMobil (7%), DONG (10%), Statoil (29%), Petoro (37%)
(NPD, 2011).
The reservoir itself lies in the “Egga” formation and consists of Paleocene sandstone at
depths of 2700 – 2900 meters subsurface. The produced gas is transported across the
120 km from wellhead to shore in two multiphase subsea pipelines. The conditions are
rather extreme with sub-­‐zero water temperatures at seabed (Norske Shell, 2011).
Hence, hydrate formation is very plausible and relevant to the successful operation of
this field.
13

Generic
The third composition I’ve chosen to include in my work is a fictional natural gas blend.
It is rich in methane and is meant to represent a typical cut of natural gas.
Natural gas is a wide term and can incorporate a variety of different compositions and
still fall under the category. It is naturally occurring, often associated with crude oil and
used as fuel. The components present in a typical natural gas are light hydrocarbons:
methane, ethane, propane, butanes and pentanes. Other heavier hydrocarbon
components may be present, but usually in vary small quantities. Natural gas may also
contain some non-­‐hydrocarbons, specifically CO2, N2 and H2S. Wet natural gas is usually
saturated with water, and this is where the signs of possible hydrate formation really
start to flash.
The so-­‐called generic composition I’ve used is determined by information in lecture
notes from TPG4140 Natural Gas (Gudmundsson, 2011).
14

Calculation Methods
A few methods for producing the dissociation curve for natural gas hydrate is selected
for comparison in this project. Some are computer simulation models, such as
AspenTech’s HYSYS software; others are simpler and performed by hand calculations. In
the following segment the various methods are explained in more detail.
HYSYS
Aspen HYSYS is a process modeling software developed by Aspen Technologies Inc.
AspenTech is a company that develops software exclusively for the process industry.
“Aspen HYSYS is a market-leading process modeling tool for conceptual design,
optimization, business planning, asset management, and performance monitoring for oil &
gas production, gas processing, petroleum refining, and air separation
industries”(AspenTech, 2011).
The first step in using HYSYS is to input the necessary components. HYSYS already
contains a database of some 1500 components, making it easy to pick and choose the
specific needed components. In the off chance that HYSYS does not contain a particular
component, the software offers the opportunity to construct hypothetical components
based on accurate estimations. The inherent components are calculated based on
comprehensive experimental data, such that they correspond as accurately as possible
to real life situations.
After specifying the component list, the composition is put directly into the program,
and normalized should the total mole fraction be unequal to one. The normalize option
preserves the ratio between each component, but changes the mole fractions such that
the total mole fraction amounts to one.
Fluid package selection is the required third step before HYSYS can perform any
simulations. The fluid package contains information about the physical and flash
properties of components. It determines the relation between each component and how
they react together.
The Peng-­‐Robinson fluid package is selected for the HYSYS simulations, as this is the
preferred fluid package for hydrocarbon mixtures. The Peng-­‐Robinson equation of state
15

is recommended for oil, gas and petrochemicals because it calculates with a high degree
of accuracy the properties of single-­‐phase, two-­‐phase and three-­‐phase systems. It is
ideal for Vapor-­‐Liquid-­‐Equilibrium (VLE) calculations over a range of hydrocarbon
systems (Aspen HYSYS Simulation Basis Manual, 2011).
Derivation of the Peng-­‐Robinson Equation of State
The Peng-­‐Robinson equation of state is a modification of the Redlich-­‐Kwong equation of
state, which again is a modification of the van der Waals equation from 1873. This
section covers the basic derivation of the Peng-­‐Robinson equation, which is the base for
the calculations performed by HYSYS. The derivation is included as theoretical
background information for the HYSYS calculations and can be found in the original
publication by Peng & Robinson (1976).
The basic equation is as follows:
P = RT
v − b −
a( T )
v(v + b) + b(v − b)
Eq. 1
where P is pressure, R is the universal gas constant, T is temperature, v is the molar
volume, a(T) is the attraction parameter and b is the van der Waals covolume. The van
der Waals covolume is defined as: “The constant b in the van der Waals equation, which is
approximately four times the volume of an atom of the gas in question multiplied by
Avogadro's number” (McGraw-­‐Hill, 2011). The molar volume is determined by the
fraction on molar mass over density:
v = M ρ
Eq. 2
Eq. 1 can be rewritten as
Z 3 − (1− B)Z 2 + (A − 3B 2 − 2B)Z − (AB − B 2 − B 3 ) = 0
Eq. 3
where
A =
aP
R 2 T 2
B = bP
RT
Z = Pv
RT
Eq. 4
Eq. 5
Eq. 6
16

At the critical temperature (Tc), the attraction parameter (a) and van der Waals
covolume (b) are given by
a( T c ) = 0, 45724 R2 2
T c
P c
b( T c ) = 0,007780 RT c
P c
Eq. 7
Eq. 8
For all other temperatures, a and b are defined as
( ) = a( T c ) !" ( T r
,# )
( ) = b( T c )
a T
b T
Eq. 9
Eq. 10
where Tr is the reduced temperature and given by
T r
= T T c
Eq. 11
The scaling factor (α) , needed in eq. 8, is given by
1
α
1
2
⎛ ⎞
2
= 1 +κ 1 − T r
⎝
⎜
⎠
⎟
Eq. 12
and the characteristic constant (κ) through
κ = 0,037464 + 1,54226ω − 0,26992ω 2
Eq. 13
ω is the acentric factor, the value of which is needed to solve the equation.
For the full derivation of the Peng-­‐Robinson equation, I advise the reader to look into
the original publication by Peng & Robinson (1976).
17

Makogon, Elgibaly & Elkamel
The first, and simplest, hand calculation used in this project is one developed by Yuri F.
Makogon (1981) and further modified in the work of Ahmed A. Elgibaly & Ali M. Elkamel
(1997) as described in J. J. Carroll’s “Natural Gas Hydrates” (2003).
In his book, “Hydrates of Natural Gas”, Makogon presents several expressions for the
relationship between pressure and temperature for hydrate formation in pure
components and select natural gasses. The expressions all follow the same form, based
on experimental evidence that the relationship between pressure and temperature for
hydrate dissociation can be described by the following equation:
log P = α ( T + kT 2
) + β
Makogon presents the following expression as applicable for hydrocarbons in the
temperature range of 0 – 25 °C:
log P = β + 0,0497( T + kT 2
)
where β and k are obtained graphically in a separate plot versus relative density.
However, both β and k can be calculated as a function of gas gravity and put into a
slightly modified expression of P (Elgibaly & Elkamel, 1997). The expressions are as
follows:
β = 2,681− 3,811γ + 1,679γ 2
k = −0,006 + 0,011γ + 0,011γ 2
The modifications to the original expression by Makogon are made to fit natural gases
better, whereas the original expression applies to pure hydrocarbon gases. The
calculated values of β and k can be used in the modified expression of P (Carroll, 2003):
log P = β + 0,0497( T + kT 2
) − 1
with P in MPa and T in °C. Although this method is not developed for sour gasses, it is
included in order to determine the degree of uncertainty when applied to sour gasses. It
is a simple method, and if the errors are small it can very well serve a purpose of
providing a good initial guess as to when hydrates can be expected to form.
18

K.K. Østergaard et al.
Like many of the other hand calculation methods, the correlation developed by
Østergaard et al. (2000) is based on gas gravity. It is applicable for a range of fluids, from
black oils to lean natural gas. It differs from many of the other available methods by the
fact that it accounts for sour gas in CO2, and inert gas in N2. It is important to note that
CO2 is the only sour gas that the correlation is designed to handle. An attempt was made
to correlate the effects of H2S, but not it was unsuccessful. As opposed to HYSYS, this
method requires few initial inputs: Gas gravity and mole fraction of components.
It is noted that the correlation itself is based on thermodynamic modeling rather than
experimental data. The authors state the reasons for this being lack of such
experimental data and the expected uncertainties of the data could very well render the
relationship between pressure and temperature impossible to correlate. The correlation
ignores the effect of heavy hydrate formers (C6+), also due to lack of reliable data.
However, at least for this work, the effect of the heavier hydrate components is assumed
to be very small due to low concentrations.
The work of Østergaard et al. resulted in the following correlation:
⎡ ( ) T + c 6
(γ + c 7
) −3 + c 8 F m
+ c 9
F 2 m
+ c 10
P HC
= exp
⎣
c 1
(γ + c 2
) −3 + c 3
F m
+ c 4
F 2 m
+ c 5
where PHC is the hydrate dissociation pressure (kPa), T is temperature (K) and γ the
specific gravity of the gas. ci are constants, given in Table 2 below, and Fm is the molar
ratio between non-­‐hydrate formers and hydrate formers. Hence, hydrate formers are
weighted more in this correlation compared to pure gravity correlations.
⎤
⎦
19

Table 2: Ci-constants used in the Østergaard et al. correlation.
The correlation doesn’t yet account for CO2 and N2. The effect of these components
comes into play through correction factors (BCO2 & BN2), which are multiplied with the
dissociation pressure calculated for the sweet gas.
B i
= ( α 0,i
F m
+ α 1,i ) f k
+ 1.000
where i = CO2, N2. fi is the component mole fraction. The constants α0,i and α1,i are given
in Table 3 below. Hence, the corrected dissociation pressure is obtained:
P( HC +CO2 + N 2 ) = P ⋅ B HC CO 2
⋅ B N2
Table 3: α-constants used in the Østergaard et al. correlation.
Applying the corrected dissociation pressure above as a function of temperature, the
hydrate dissociation curve for the given gas can be calculated.
20

The Baille-­‐Wichert Method
The Baille-­‐Wichert method is a hand calculation method developed to enable hydrate
prediction in sour gasses. It is the only hand calculation method found that incorporates
the presence of H2S when calculating the hydrate forming conditions. However, no
calculations have been preformed using this method, and it is not represented in the
results section.
The method itself is gravity based and utilizes charts that are not exactly
straightforward to use. Therefore, the Baille-­‐Wichert method is very sensitive to error
when reading these charts.
The Baillie-­‐Wichert method is not used in this project for a couple of reasons. First, it is
an iterative method, meaning it is extremely tedious to calculate the correct pressures
over a range of temperatures, which is required in order to get a hydrate dissociation
curve. The fact that the method relies on the use of charts also excludes the possibility of
designing a simple program to perform the calculations because new values have to be
read manually from the chart for each iteration step. The second reason the Baillie-­‐
Wichert method is considered inapplicable is that the charts are really hard to read for
the three example gas mixtures. The method is applicable to gasses with a specific
gravity between 0,6 -­‐1,0, whereas the Shtokman, generic and Ormen Lange mixtures
have specific gravities of 0,587, 0,581 and 0,625, respectively. Since the specific gravities
are at the lower limit of the applicable specific gravities, the chart is very difficult to read
and there is much uncertainty related to the obtained values.
Although the Baillie-­‐Wichert method is not used, it is included in this project as a sole
example of a hand calculation method that incorporates the effects of H2S in the
calculation results. It is also highlighted that the method can be much more useful if the
problem at hand is to determine whether or not hydrates can be expected to form at
given specific conditions.
21

Results
As described in the problem statement, there is more than one purpose of this project.
Therefore, this section is divided into several parts, covering how well the analytical
models correspond with the computer model (HYSYS), what parameters affect the
dissociation pressure most and describing how acid components alter the hydrate
forming conditions. Only examples are given in this section. For the complete results
please refer to Appendix A.
Model comparisons
Ideally, the three models (Makogon et al., Østergaard et al. and HYSYS) should give quite
similar results, though some deviations have to be expected. The calculations are
performed using the same gas compositions and conditions for each model. The gas
compositions for Shtokman, Generic and Ormen Lange are given below:
Gas Compositions
Component [xi] Shtokman Generic Ormen Lange
C1 0.9540 0.9600 0.9251
C2 0.0170 0.0300 0.0345
C3 0.0050 0.0050 0.0122
C4 (i + n) 0.0026 0.0030 0.0059
C5 (i + n) 0.0034 0.0020 0.0148
N2 0.0130 0.0000 0.0034
CO2 0.0050 0.0000 0.0043
H2S 0.0000 0.0000 0.0000
Total 1.0000 1.0000 1.0000
Table 4: Field compositions.
None of the gases contain significant amounts of acid components and all contain fairly
high amounts of methane. The hydrate formers’ mole fraction make up 97,86%, 99,80%
and 97,77% of the total mole fraction, respectively. Hence, hydrate formation is very
plausible in every case.
22

When comparing the three models, HYSYS is considered a reference point, as the
calculations obtained from this model are more comprehensive and thus provides a
more accurate result. Thereafter, it is interesting to see how the correlations presented
by Østergaard et al. and Makogon et al. measure against each other and against the
HYSYS results. Both of the analytical models are designed for natural gases, the Makogon
et al. correlation being the easiest to use, whereas the Østergaard et al. correlation is
better suited to handle acid components.
Figure 3: Model comparison – Ormen Lange
From the curve above, and considering results from the Ormen Lange and generic
natural gas found in Appendix A, the Makogon et al. correlation is surprisingly accurate
for low temperatures. As the temperature increases, it deviates from the HYSYS results,
underestimating the dissociation pressure. The Østergaard et al. correlation also seems
to underestimate the dissociation pressure, though to a greater extent for low
temperature cases. As the temperature increases, the Østergaard et al. dissociation
curve approaches and intersects the Makogon et al. dissociation curve.
23

From the results, the correlation by Makogon et al. is preferable for sweet gas. For sour
gas, the results may not be the same, keeping in mind that the Makogon et al. correlation
isn’t designed to handle such compositions.
The correlation presented by Østergaard et al. (2000) is designed to correct for presence
Figure 4: N2 and CO2 correction using the Østergaard et al. correlation - Shtokman
of CO2 and N2. And below a curve showing the correction for CO2 and N2 is presented.
As can be seen from the curve, the correction is only slight. However, this is mainly due
to the low CO2 and N2 content of the Shtokman gas. Gas from Ormen Lange also contains
CO2 and N2, but even smaller quantities, so the correction correspondingly small. The
generic gas mixture does not contain any CO2 or N2; hence there is no correction to be
made.
Effect of H 2 S and model applicability
As the effects of CO2 and N2 are described both in Gudmundsson’s manuscript for his
book on flow assurance (2010) and in the paper presented by Østergaard et al. (2000),
the effects of H2S has been investigated closer to get an idea of how it affects the natural
gas hydrate dissociation pressure. By varying the H2S content of the three gases, the
24

effects are displayed by calculating the dissociation curve for each case. The results from
HYSYS are the only results that can be trusted, but the same approach has been used
with both the Makogon et al. and Østergaard et al. method in order to see how well they
correspond.
With H2S mole fractions of 0%, 1%, 10% and 20% the curves below are produced by
HYSYS. The compositions are assumed to be reasonable based on historical data as
described in Carroll (2003) and Elshahawi & Hashem (2005).
Figure 5: Effect of H2S content. HYSYS results – Ormen Lange
Clearly, H2S facilitates the formation of hydrates in natural gas. As the H2S content
increases, the curve shifts such that the dissociation occurs at higher temperatures. The
hydrate dissociation curves account for all types of hydrates that form, not only the
hydrates formed by hydrocarbon hydrate formers. Increasing the fraction of hydrate
formers by adding H2S, which is a Type 1 hydrate former, might be a valid explanation
for the significant negative effect it has on prevention of hydrate formation for a given
gas composition. Also, the effect of the non-­‐formers becomes less significant due to the
non-­‐former mole fraction being reduced.
25

It is hard to predict, and not always logical, what type of hydrate that will form in
natural gas mixtures. For instance, methane and ethane, which are both Type 1 hydrate
formers, will form Type 2 hydrates in a mixture. Mixtures containing non-­‐formers are
hard to predict because the non-­‐formers often are heavy hydrocarbons. Therefore, the
mixture’s hydrate dissociation pressure depends on the non-­‐formers’ tendency to
liquefy. Hydrates may still form in a liquid, but at different conditions (Carroll, 2003).
The increasing mole fraction of light hydrocarbon-­‐formers may be a good explanation as
to why hydrates form more easily with added H2S. It reduces the effect of the heavier
non-­‐forming hydrocarbons and facilitates formation, being a Type 1 former.
The same approach as for HYSYS has been used with the Makogon et al. and Østergaard
et al. correlations to see how well they correspond with HYSYS in the presence of H2S.
The curves are given overleaf.
26

Figure 6: Effect of H2S content. Makogon et al. – Ormen Lange
Figure 7: Effect of H2S content. Østergaard et al. – Ormen Lange
27

Discussion
To start of with, gas composition, acid components, and salinity all have an effect the
dissociation of natural gas hydrate. The effect of composition depends on the
components in place and can have both positive and negative effects. The most obvious
effect of composition is the content of potential hydrate formers. The hydrocarbon
hydrate formers include methane, ethane, propane and butane. For this reason, it is
completely unrealistic to expect no hydrocarbon formers in a natural gas, as they
include four of the most essential components in natural gas. Still, lower content of
hydrate formers makes the mixture less prone to hydrate formation. The specific gravity
of a gas also shows to have an effect, as can be seen by the Makogon et al. correlation
results, and Østergaard et al. to some extent. Heavier gas causes the dissociation
pressure to increase. This statement isn’t entirely applicable to all components, but it
has shown to be descriptive for hydrocarbon components. Other components usually
found in natural gas, such as CO2, N2 and H2S, deviate from this trend. This is also what
makes simple hand calculation methods for hydrate dissociation pressure difficult to
obtain.
N2 exhibits a higher dissociation pressure than the hydrocarbon hydrate formers,
whereas CO2 and H2S have lower pressures. The Østergaard et al. correlation accounts
for the effects of both N2 and CO2, and the correction for these two components indicate
that they tend to increase the dissociation pressure when appearing together. This is
perhaps mostly due to the N2 content. As can be seen from the N2-­‐ and CO2-­‐corrected
curves obtained using the Østergaard et al. correlation, the correction is somewhat
larger for the Shtokman gas than that of Ormen Lange. This corresponds well with the
previous statement since the Shtokman gas is richer in nitrogen. A few variations in the
CO2 and N2 content also show that the correction for N2 versus CO2 is much greater. A
systematic approach to this phenomenon as not been applied simply because of time
limitations. However, it could be an idea for further work.
Since the Østergaard et al. correlation does not account for the effects of H2S, more
efforts have been put towards identifying the effects using a systematic approach in
HYSYS. The results show that by increasing the content of H2S by 1%, 10% and 20%
dissociation occurs at higher temperatures. The temperature increase seems to not
correspond with the relative increase in H2S content. For instance, going from no H2S to
28

10% H2S represents a bigger temperature elevation than going from 10% to 20%. Going
from no H2S to 1% supports the assumption that the amount of H2S added might not be
directly related to the shift of the dissociation curve. Also, the effect of added H2S is
greater as the pressure increases.
Results from the Makogon et al. correlation follow the same trend as the HYSYS results,
although they are less significant. The indication that the amount added of H2S not
necessarily resulted in an equally significant temperature elevation is also further
backed up. 1% and 10% increase in H2S seem to have a greater relative effect on the
dissociation curve than adding 20%.
The effects of salinity are not shown by calculations, but researching the subject
indicates that it has an inhibiting effect as it lowers the hydrate formation temperature.
The work of Mohammadi & Richon (2007) shows that the effect of salt on the formation
of hydrates is analogous to the effect of salinity on the freezing-­‐ and boiling points of
water. Put simply, increased salinity will stretch the temperature scale in both directions
causing freezing to occur at lower temperature and boiling at higher temperatures. The
idea of investigating boiling point elevations due to increased water salinity lead to the
successful correlation to the case of lowered hydrate dissociation temperature.
Methanol, ethanol, (mono-­‐) ethylene glycol, diethylene glycol and triethylene glycol are
commonly used hydrate inhibitors. The type of inhibitor used is very much based on the
situation and there are pros and cons related to each one. For instance, a disadvantage
with both methanol and ethanol is their volatility, as a certain amount of inhibitor tends
to vaporize out of solution. This is considered a loss of inhibitor and needs to be
accounted for when the amount of required inhibitor is calculated. Hence, the
Hammerschmidt equation might not be enough on its own, but more satisfactory along
with common charts for reading the inhibitor vaporization for the given type of
inhibitor. The glycols are less volatile than methanol and ethanol by a factor of 100 and
losses using these types of inhibitors are generally considered negligible. Overleaf,
Figure 8 shows provides an overview of the mentioned inhibitors’ vapor pressure:
29

Figure 8: Inhibitor vapor pressures.
Another disadvantage related to the most common inhibitors is their flammability.
Methanol is by far the most flammable substance and represents a significant fire
hazard. Especially if storing on offshore facilities is required, the use of methanol has to
be very carefully considered. An outbreak of fire under such circumstances would
obviously be much more severe than other situations on land with good evacuation
possibilities and more extinguishing resources. Do note the fact that all of the mentioned
inhibitors are flammable; some are just more than others. Until now, it seems that
glycols are the preferred type of inhibitor, and one can argue the case that they are, but
the economics have not yet been mentioned. Methanol is very cheap compared to the
glycol inhibitors and since large quantities often are required the price becomes
something that needs to be taken under consideration.
30

Base price of inhibitor is given below (Carroll, 2003):
Inhibitor
Methanol
Ethanol
MEG
DEG
TEG
Base Price [$/gal]
1.60
3.30
5.87
7.00
8.44
Table 5: Inhibitor base price.
This means that TEG is over 5 times more expensive than methanol. Obviously, this
price difference is not negligible.
The Makogon et al. correlation seems surprisingly accurate. Using HYSYS as a reference
point, it corresponds much better than the Østergaard et al. correlation. Seeing how the
Østergaard et al. correlation is supposed to account for the effects of N2 and CO2, it is not
as accurate as expected. It underestimates the dissociation pressure significantly
compared the Makogon et al. correlation for the three cases investigated in this project.
However, in cases with different compositions the results may be different. The
Østergaard et al. correlation is tedious and hard to use without a spreadsheet.
Contrarily, the Makogon method is much more straightforward and easy to use. It could
very well work with only a simple calculator, pen and paper making it very useful in the
field or in situations where a quick estimate of the hydrate forming conditions are
required.
31

Conclusion
By comparison between all the models for calculating the dissociation pressure of
natural gas hydrate, the Makogon et al. stands out as the preferred hand calculation
method to use. The only data needed is the gas gravity in order to make a prediction of
whether hydrates will form or not at a given temperature or pressure. Caution should be
used when applying the Makogon et al. correlation to sour natural gas mixtures.
H2S has a negative effect on the dissociation pressure of natural gas hydrate, increasing
the hydrate dissociation temperature. The effect of H2S also seems more significant than
that of CO2 and N2. Temperature elevation of added H2S seems to increase with
pressure.
The Østergaard et al. correlation offers some purpose in producing an initial estimate of
the hydrate forming conditions. It is also the only hand calculation method found that is
designed to handle CO2 and N2. N2 has a bigger and positive effect on the dissociation
pressure of natural gas hydrate, as opposed to CO2.
Salinity lowers the hydrate dissociation temperature and has an inhibiting effect. There
exist an easy and straightforward method to predict the salt-­‐induced temperature
depression presented in the work of Mohammadi & Richon (2007). A weakness is that
knowledge about normal boiling point elevations of the aqueous solution with respect to
water is a prerequisite.
Lastly, the type of inhibitor used should be determined from a safety, technical and
economic point of view. MEG, DEG and TEG are best from a safety and technical point of
view, but they are fairly expensive compared to methanol and ethanol. With methanol
being more than five times cheaper to purchase, it seems more reasonable in situations
that require large amounts of inhibitor. A mix of inhibitors could be a favorable
compromise by diluting expensive glycols with less expensive methanol or ethanol.
32

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35

Appendix A
Model Comparisons
Figure A1: Model Comparison - Shtokman
Figure A2: Model Comparison - Generic
Figure A3: Model Comparison – Ormen Lange
36

Østergaard et al. correction for N 2 and CO 2
Figure A4: Østergaard Dissociation Curves - Shtokman
Figure A5: Østergaard Dissociation Curves – Ormen Lange
37

Effect of H 2 S – HYSYS
Figure A6: HYSYS Effect of H2S - Shtokman
Figure A7: HYSYS Effect of H2S - Generic
Figure A8: HYSYS Effect of H2S – Ormen Lange
38

Effect of H 2 S – Østergaard et al.
Figure A9: Østergaard et al. Effect of H2S - Shtokman
Figure A10: Østergaard et al. Effect of H2S - Generic
Figure A11: Østergaard et al. Effect of H2S – Ormen Lange
39

Effect of H 2 S – Makogon et al.
Figure A12: Makogon et al. Effect of H2S - Shtokman
Figure A13: Makogon et al. Effect of H2S - Generic
Figure A 14: Makogon et al. Effect of H2S – Ormen Lange
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