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ADVANCES IN NATURAL GAS UTILIZATION
A RESEARCH STUDY
WRITTEN BY
UDOSEN, ENOBONG JOSEPH
10/EG/CE/335
SUBMITTED TO
DR. S. B. ALABI
DEPARTMENT OF CHEMICAL/PETROLEUM
ENGINEERING,
FACULTY OF ENGINEERING,
UNIVERSITY OF UYO.
AUGUST, 2015
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TABLE OF CONTENTS COVER PAGE ……………………………………………………………………………………………..1
TABLE OF CONTENTS ………………………………………………………………………………2 - 3
LIST OF TABLE .......................................................................................................................................... 4
LIST OF FIGURE......................................................................................................................................... 4
ACKNOWLEDGEMENT ............................................................................................................................ 5
ABSTRACT .................................................................................................................................................. 6
CHAPTER ONE ........................................................................................................................................... 7
INTRODUCTION ........................................................................................................................................ 7
1.1 BACKGROUND OF THE STUDY ............................................................................................. 7
1.2 AIM AND OBJECTIVE OF THE STUDY .................................................................................. 8
1.3 SCOPE OF THE STUDY ................................................................................................................... 8
CHAPTER TWO .......................................................................................................................................... 9
LITERATURE SURVEY ............................................................................................................................. 9
2.1 HISTORY OF NATURAL GAS ........................................................................................................ 9
2.2 ORIGIN OF NATURAL GAS ......................................................................................................... 11
2.3 NATURE AND COMPOSITION OF NATURAL GAS ................................................................. 12
2.4 PRETREATMENT OF NATURAL GAS ........................................................................................ 13
2.4.1 CHALLENGES ......................................................................................................................... 14
2.4.2 ACID GAS REMOVAL ............................................................................................................ 15
2.4.3 INCINERATION ....................................................................................................................... 16
2.4.4 DEHYDRATION....................................................................................................................... 17
2.4.5 MERCURY REMOVAL ........................................................................................................... 17
2.4.6 DEVELOPMENTS IN PRE-TREATMENT ............................................................................. 18
2.5 CONVERSION OF NATURAL GAS TO POWER ........................................................................ 19
2.6 PROCESSING OF NATURAL GAS TO USEFUL PRODUCTS ................................................... 21
2.6.1 EQUIPMENT USED AND DESCRIPTION ............................................................................. 21
2.7 TECHNOLOGIES IMPLORED ....................................................................................................... 23
2.7.1 PROCESS SELECTION FACTORS ......................................................................................... 23
2.8 CRYOGENIC PROCESS ................................................................................................................. 24
2.8.1 BASIC SEPARATION PRINCIPLE FOR CRYOGENIC PROCESS ...................................... 24
2.9 TECHNICAL AND ECONOMIC IMPLICATION OF NATURAL GAS PROCESSING ............. 25
2.9.1 FLARING OF NATURAL GAS ............................................................................................... 26
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2.9.2 NIGERIA LEGISLATION IN FAVOUR OF NATURAL GAS UTILIZATION .................... 28
2.10 NATURAL GAS UTILIZATION OPTIONS. ............................................................................... 29
2.11 STATUS OF NIGERIA IN NATURAL GAS UTILIZATION...................................................... 30
2.12 SOURCES OF NATURAL GAS IN NIGERIA ............................................................................. 35
CHAPTER THREE .................................................................................................................................... 37
CONCLUSION AND RECOMMENDATION .......................................................................................... 37
3.1 CONCLUSION ................................................................................................................................. 37
3.2 RECOMMENDATION .................................................................................................................... 37
BIBLIOGRAPHY ................................................................................................................................... 38
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LIST OF TABLE
1. Overall comparisons of natural gas purification technologies - - 25
LIST OF FIGURE
1. Stages showing the conversion of natural gas to electrical power- - 20
2. Simplified schematic representation of a gas processing plant - - 21
3. Top natural gas flares in the world - - - - - 27
4. The Niger Delta region of Nigeria - - - - - - 36
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ACKNOWLEDGEMENT
My heartfelt love to Almighty God my maker and father who has overwhelmed me with his
infinite mercy and faithfulness
My profound gratitude is due to my course lecturer Dr. Alabi for his firm motivation to bringing
out the best in his students.
I acknowledge my humble parents and sponsors for their consistent supports all through my
academic sojourn in this place.
I equally appreciate my colleagues and all other person or group of persons who in one way or
the other contributed to the success of this review.
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ABSTRACT Known for its versatility and clean burning nature, natural gas can be used as a fuel or a chemical
feedstock. In the past the development of new natural gas conversion technologies suffered from
the small price differential between products and natural gas. Lately the role of natural gas in
meeting domestic energy and feedstock materials demand has attracted tremendous interest;
mostly due to its new found abundance in Nigeria, low current U.S. natural gas prices relative to
crude oil, and Its cleaner and more efficient combustion compared to other fossil fuels.
It is projected that natural gas conversion to petrochemicals and fuels will rise substantially in
the next 20 years and advances in development of new sustainable routes for natural gas
utilization will be strongly promoted by increasing efforts and expertise in all of the areas of
knowledge involved (Process Economics Program Report 275, Dec 2010).
In its gaseous form, natural gas is difficult to transport and store, limiting the scope of its
utilization compared with coal and oil. However, natural gas usage has increased sharply in
recent years along with the expanding use of LNG. By 2035, demand is expected to be more than
1.4 times, what it is today equivalent to an annual growth rate of 1.4%. Furthermore, amid
increasing demand for energy due to growing use as the most efficient and practical energy for
making the transition to low-carbon society.
This paper review will discuss the advances made in utilizing natural gas, the recent technologies
implored and the environmental implication of harnessing the gas.
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CHAPTER ONE
INTRODUCTION
1.1 BACKGROUND OF THE STUDY
Natural gas is a vital component of the world‟s supply of energy. It is one of the cleanest, safest,
and most useful of all energy (Kohl and Nielson, 1997). It is one of the most important fuels in
our life as it is one of the principal sources of energy for many of our day- to- day needs and
activities (Bourke and Mazzoni, 1989). It plays an important role in the development of countries
and building strong economies because it is a source of energy for household, industrial and
commercial use, as well as electricity generation (Haring, 2008).
Natural gas is a gaseous fossil made essentially from the remains of plants, animals and micro-
organisms that lived millions of years ago. Natural gas is colourless, shapeless, and odourless in
its pure form. It is a combustible mixture of hydrocarbon gases. While natural gas is formed
primarily of methane, it may also include ethane, propane, butane and pentane. Natural gas, in
itself might be considered to be quite uninteresting – except that it is combustible, abundant in
nature and when burned, it gives off a great deal of energy and few emissions. Unlike other fossil
fuels, natural gas is clean burning and emits lower levels of potentially harmful by-products into
the air. The constant need of energy to heat our homes, cook our food, and generate our
electricity has elevated natural gas to such a level of importance in our society, and in general,
our lives (www.naturalgassprocessing.org.ng).
The raw natural gas consists primarily of methane, (CH4) the shortest and lightest hydrocarbon
molecule, heavier gaseous hydrocarbons, ethane (C2H4), propane (C3H8), normal butane (n-
C4H10), pentanes(C5H12) and even higher molecular weight hydrocarbon, when processed and
purified into finished by-products, all of those are collectively referred to as (Natural gas
liquids)- acid gases carbon dioxide (CO2), hydrogen sulphide (H2S) and mercaptans such as
methanethiol (C2H5SH) (Haring 2008). Mercaptans are odorants added to the natural gas before
it is delivered to the end- user to aid in detecting leaks. It has a characteristic rotten egg smell
(http://www.naturalgas.org).
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1.2 AIM AND OBJECTIVE OF THE STUDY
The aim and objective of this study is to analyze some advances made in the course of utilizing
natural gas with a focus on Nigeria.
1.3 SCOPE OF THE STUDY
In this study, adequate attention will be given to natural gas sources, pre- treatment activities
associated with it, processing and conversion of the gas to liquids, various chemicals and other
useful products. In the same vein, equipment and technologies involved in processing the gas, its
economic implications globally and in Nigeria and states where the gas can be processed and
utilized in Nigeria are also discussed.
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CHAPTER TWO
LITERATURE SURVEY
2.1 HISTORY OF NATURAL GAS
Natural gas is nothing new. In fact, most of the natural gas that is brought out from under the
ground is millions and millions of years old. However, it was not until recently that methods for
obtaining this gas, bringing it to the surface, and putting it to use were developed.
Before there was an understanding of what natural gas was, it posed a mystery to man.
Sometimes, lightning strikes would ignite natural gas that was escaping from under the earth‟s
crust. This would create a fire coming from the earth, burning the natural gas as it seeped out
from underground. These fires puzzled most early civilizations, and were the root of myth and
superstition. One of the most famous of these flames was found in ancient Greece, on Mount
Parnassus around 1000 B.C. A goat herdsman came across what looked like a „burning spring‟, a
flame rising from a fissure in the rock. The Greeks, believing it to be of divine origin, built a
temple on the flame. This temple housed a priestess who was known as the Oracle of Delphi,
giving out prophecies she claimed were inspired by the flame.
These types of springs became prominent in the religions of India, Greece, and Persia. Unable to
explain where these fires came from, they were often regarded as divine, or supernatural. It
wasn‟t until about 500 B.C. that the Chinese discovered the potential to use these fires to their
advantage. Finding places where gas was seeping to the surface, the Chinese formed crude
pipelines out of bamboo shoots to transport the gas, where it was used to boil sea water,
separating the salt and making it palatable.
Britain was the first country to commercialize the use of natural gas. Around 1785, natural gas
produced from coal was used to light houses, as well as streetlights.
Manufactured natural gas of this type (as opposed to naturally occurring gas) was first brought to
the United States in 1816, when it was used to light the streets of Baltimore, Maryland. However,
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this manufactured gas was much less efficient, and less environmentally friendly, than modern
natural gas that comes from underground.
Naturally occurring natural gas was discovered and identified in America as early as 1626, when
French explorers discovered Native Americans igniting gases that were seeping into and around
Lake Erie. The American natural gas industry got its beginnings in this area. In 1859, Colonel
Edwin Drake (a former railroad conductor who adopted the title „Colonel‟ to impress the
townspeople) dug the first well. Drake hit oil and natural gas at 69 feet below the surface of the
earth.
Most historians characterize this well as the beginning of the natural gas industry. A two-inch
diameter pipeline was built, running 5 and ½ miles from the well to the village of Titusville,
Pennsylvania. The construction of this pipeline proved that natural gas could be brought safely
and relatively easily from its underground source to be used for practical purposes.
In 1821, the first well specifically intended to obtain natural gas was dug in Fredonia, New York
by William Hart. After noticing gas bubbles rising to the surface of a creek, Hart dug a 27-foot
well to try and obtain a larger flow of gas to the surface. Hart is regarded by many as the „father
of natural gas‟ in America. Expanding on Hart‟s work, the Fredonia Gas Light Company was
eventually formed, becoming being the first American natural gas company
(http://en.wikipedia.org/wiki/fredonia_gas_light_company).
During most of the 19th century, natural gas was used almost exclusively as a source of light.
Without a pipeline infrastructure, it was difficult to transport the gas very far, or into homes to be
used for heating or cooking. Most of the natural gas produced in this era was manufactured from
coal, rather than coming from a well. Near the end of the 19th century, with the advent of
electricity, natural gas lights were converted to electric lights. This led producers of natural gas
to look for new uses for their product.
In 1885, Robert Bunsen invented what is now known as the Bunsen burner. He managed to
create a device that mixed natural gas with air in the right proportions, creating a flame that
could be safely used for cooking and heating. The invention of the Bunsen burner opened up new
opportunities for the use of natural gas in America, and throughout the world. The invention of
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temperature-regulating thermostatic devices allowed for better use of the heating potential of
natural gas, allowing the temperature of the flame to be adjusted and monitored.
Without any way to transport it effectively, natural gas discovered pre-WWII was usually just
allowed to vent into the atmosphere, or burnt, when found alongside coal and oil, or simply left
in the ground when found alone.
One of the first major pipelines was constructed in 1891. This pipeline was 120 miles long, and
carried natural gas from wells in central Indiana to the city of Chicago. However, this early
pipeline was not very efficient at transporting natural gas. It wasn‟t until the 1920s that
significant effort was put into building a pipeline infrastructure. After World War II, new
welding techniques, along with advances in pipe rolling and metallurgy, further improved
pipeline reliability. This post-war pipeline construction boom lasted well into the „60s, and
allowed for the construction of thousands of miles of pipeline in America.
Once the transportation of natural gas was possible, new uses for natural gas were discovered.
These included using natural gas to heat homes and operate appliances such as water heaters,
ovens, and cooktops. Industry began to use natural gas in manufacturing and processing plants.
Also, natural gas was used to heat boilers used to generate electricity. The expanded
transportation infrastructure had made natural gas easy to obtain, and it was becoming an
increasingly popular energy choice.
2.2 ORIGIN OF NATURAL GAS
Like other non-renewable fossil fuels, natural gas is essentially formed from the
decomposition of living matters such as plants, animals and micro-organisms that lived over
millions of years ago and became an inanimate mixture of gases. Although there are various
theories about the origin of fossil fuels, the most widely accepted theory states that fossil
fuels are usually formed when organic matters are decayed and compressed under the
earth‟s crust at high pressure and for a very long time. This kind of formation is technically
referred to as thermogenic methane. This type of natural gas is formed by the
decomposition process of the piled and compressed organic matters that are covered in
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mud, sediment and debris at high temperature beneath the crust of the earth. In another
way, natural gas can also be formed by the action of tiny methane-producing
microorganisms and it is technically termed as biogenic methane. In this case, methane
formation usually takes place close to the earth‟s surface and the methane produced is
usually dissipated into the atmosphere. However, in some cases, this methane can be trapped
underground and recovered as natural gas. As a third theory, natural gas is formed by a biogenic
process where this process takes place at extremely underneath the earth's crust, where hydrogen-
rich gases and carbon molecules are dominant. These gases may
interact with minerals found in the underground in the absence of oxygen by the time the
gases gradually rise towards the surface of the earth. In such processes reaction will take
place and forms gaseous compounds such as nitrogen, carbon dioxide, oxygen, water and
inert gases like argon. Hence, the condition will form methane deposits at very high
pressure, similar to that of the thermogenic methane (NaturalGas.org 2010).
2.3 NATURE AND COMPOSITION OF NATURAL GAS
The natural gas processed at the wells will have different range of composition depending
on type, depth, and location of the underground reservoirs of porous sedimentary deposit
and the geology of the area. Most often, oil and natural gas are found together in a reservoir.
When the natural gas is produced from oil wells, it is categorized as associated with (dissolved
in) crude oil or non-associated. It is apparent that two gas wells producing from the same
reservoir may have different compositions. Further, the composition of the gas produced from a
given reservoir may differ with time as the small hydrocarbon molecules (two to eight carbons)
in addition to methane that existed in a gaseous state at underground pressures will become
liquid (condense) at normal atmospheric pressure in the reservoir. Generally, they are called
condensates or natural gas liquids (NGLs). This usually happens in a retrograde condensate
reservoir (Beggs 1984; Bahadori, Mokhatab et al. 2007).
As one of the major contaminates in natural gas feeds, carbon dioxide must optimally be
removed as it reduces the energy content of the gas and affect the selling price of the natural
gas. Moreover, it becomes acidic and corrosive in the presence of water that has a potential
to damage the pipeline and the equipment system. In addition, when the issue of
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transportation of the natural gas to a very far distance is a concern, the use of pipelines will
be too expensive so that Liquefied Natural Gas (LNG), Gas to Liquid (GTL) and chemicals
are considered to be an alternative option. In LNG processing plant, while cooling the
natural gas to a very low temperature, the CO2 can be frozen and block pipeline systems and
cause transportation drawback. Hence, the presence of CO2 in natural gas remains one of
the challenging gas separation problems in process engineering for CO2/CH4 systems.
Therefore, the removal of CO2 from the natural gas through the purification processes is
vital for an improvement in the quality of the product (Dortmundt and Doshi 1999).
As a gaseous fossil fuel, natural gas is relatively low in energy content per unit volume and
emits lower quantities of greenhouse gases (GHG) than other fossil fuels (Pascoli, Femia et
al. 2001). However, when compared with other hydrocarbon energy sources, it is the most
hydrogen-rich and has higher energy conversion efficiencies (Economides and Wood 2009).
Natural gas consists primarily of methane (70-90% of the total component) and other light
and heavier hydrocarbons. The impurities present in natural gas need to be removed to
meet the pipeline quality standard (NaturalGas.org 2010).
Generally, the following standards are used for natural gas specification in pipeline
grid (Tobin J., Shambaugh P. et al. 2006). The natural gas should be (i) within a specific Btu
content range (1,305 Btu per cubic feet, +/- 50 Btu) (ii) delivered at a specified hydrocarbon
dew point temperature level (below which any vaporized gas liquid in the mix will tend to
condense at pipeline pressure (iii) contains no more than trace amounts of elements such as
hydrogen sulfide, carbon dioxide, nitrogen, water vapor, and oxygen (iv) free of particulate
solids and liquid water that could be detrimental to the pipeline or its ancillary operating
equipment. Comparatively carbon dioxide, that is produced from oil and coal, a GHG linked to
global warming, has approximately higher production rate (1.4 to 1.75 times) than does from
natural gas (Kidnay, Parrish et al. 2006).
2.4 PRETREATMENT OF NATURAL GAS
Natural gas generally requires removal of H2S, CO2, and COS, organic sulphur compounds,
mercury and water prior to liquefaction in order to meet product specifications, avoid blockages
and to prevent damage to process equipment. The cost of pre-treatment is dependent on the type
and concentrations of the contaminants in the natural gas.
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Most of the operational base load LNG plants process feed gases with only low concentrations of
CO2, mercury and water as contaminants. This type of gas requires the „minimum‟ of treating,
often comprising of a CO2 removal unit, and molecular sieves for drying and a carbon bed for
mercury removal.
The type of contaminants and their concentration in the natural gas affect the overall LNG
production cost. In the past most feed gases for base load LNG plants only contained CO2 (<< 10
mol %) with traces of H2S. This type of gas requires the „minimum‟ of pre-treatment.
As the market for LNG has expanded and more gas fields become economically viable to
develop there has been a need to treat feed gases richer in CO2 , H2S, COS and mercaptans. This
naturally increases the cost of the liquefaction pre-treatment, due to larger acid gas removal units
and the requirement for a sulphur recovery step. The same economic forces also push the limits
of required operating window to for example colder feed gas temperatures and higher operating
pressures.
The requirement for drying and mercury removal has remained basically constant.
2.4.1 CHALLENGES
In the recent years, economic forces have led to gas fields with more challenging treating
requirements to be considered for development. At the same time ever more emphasis has been
put on identifying the lowest cost fit for purpose design package. As always, increasingly tighter
environmental constraints, including Greenhouse emissions, have been applied to new projects.
Most current plants treat gas with less than 10% CO2 but developments with up to 60% CO2 are
now being considered. Fields containing higher levels of sulphur (H2S, COS, organic sulphur
components) are being developed. Higher pressure operation and offshore treating are also being
considered. In addition the combination of low feed temperatures and low CO2 content requires
increased investment for most solvent based technologies.
With the forces described above and the emergence of new treating technologies and vendors it
becomes increasingly important to identify the best overall integrated solution for LNG
pretreatment.
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2.4.2 ACID GAS REMOVAL
The wet absorption (solvent based) acid gas removal still remains clearly the most cost effective
for base load LNG applications. Developments in cryogenic and membrane CO2 removal have
yet to threaten the position of the solvent based processes when deep removal of CO2 for LNG
production is required.
Three basic types of liquid absorption processes are available:
Physical absorption processes, which use a solvent that physically absorbs CO2, H2S
and organic sulphur components. Examples are the Purisol and Selexol processes.
Chemical absorption processes, which chemically absorb the H2S, CO2 and to some
extent COS. Organic sulphur components do not chemically react with the solvent.
Common examples are amine processes, using aqueous solutions of alkanol amines such
as MEA, DEA, MDEA, DIPA and Flexsorb, and the carbonate processes, such as the
Benfield process.
Mixed solvents, are a mixture of a chemical and a physical solvent. The most widely
known process is the Shell Sulfinol Process, which applies a mixture of sulfolane, water
and DIPA (diisopropanolamine) or MDEA (methyldiethanolamine), Sulfinol-D and
Sulfinol-M respectively. It combines to a large extent the advantages of a chemical with
those of a physical solvent. One of the strengths of the Sulfinol process is the capability
to simultaneously remove organic sulphur compounds and COS, which are not removed
by pure chemical solvents. These characteristics make it the obvious choice for many
natural gas treating problems. The Flexsorb SE process also combines sulfolane and an
amine and is in many ways similar way to Sulfinol.
In the oldest base load LNG plants MEA, DEA and carbonate processes are applied. In the
early seventies the Sulfinol process was introduced and recently there has been one retrofit
application of a formulated MDEA solvent (Badak, Indonesia).
The Shell Sulfinol process is the most widely applied acid gas removal process in the base load
LNG industry (~40% of current installed capacity) and has also been chosen for the majority of
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new projects currently under construction. In total there are about 200 Sulfinol units worldwide.
The main advantages of the process are:
the capability of simultaneously removing H2S, CO2, COS and organic sulphur
components,
a high reliability, because sulfolane acts as a foam inhibitor resulting in a lower foaming
tendency than aqueous amine solvents, and because of the low solvent corrosivity,
the low specific energy consumption,
the physical character of the solvent can be varied by choosing the relative amounts of
water and sulfolane to trim the COS and mercaptans removal,
a lower water content in treated gas compared to aqueous amines
widely available solvent components not restricted to a proprietary supplier,
the ability to treat cold, low CO2 gas where rich solvent temperatures approach 200C
the ability to operate at pressures well above 100 bars.
2.4.3 INCINERATION
If the acid gas removal off-gas only contains CO2 it can be vented, however if H2S and/or
aromatics are present, even in small amounts, the gas must be sent to an incinerator to prevent
unsafe situations. The incinerator is normally of the thermal type, operating at about 8000C, to
achieve nearly complete H2S combustion (< 10 ppm). If a Claus and/or SCOT unit are used the
tail gas must also be incinerated. Modern adsorption materials also present the possibility of
removing low levels of H2S by fixed beds where it is permitted to vent the balance of the acid
gas stream.
An interesting recent development is the option of using the hydrocarbon containing CO2 off-gas
as fuel in steam boilers or furnaces. This concept can eliminate the need for an incinerator or
allow for a considerably smaller incineration unit.
With the increasing emphasis on reduction of greenhouse gas emission the option of acid gas
recompression and subsequent re-injection is now being considered.
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2.4.4 DEHYDRATION
The sweet gas leaving the acid gas removal step is saturated with water because most sweetening
solvents are aqueous solutions. First, the bulk of the water is condensed and separated from the
gas stream by cooling. The cooling is limited to temperatures above the hydrate formation
temperature (~20 0C). The water content is then further reduced to 0.5 ppm by drying, normally
with molecular sieves (4A-type). At least two of these dryers are required for each train; one is in
adsorption service while the other is being regenerated by heated dry gas. The adsorption
capacity of the molecular sieve decreases within two to four years to a level where it is necessary
to replace the deactivated material.
Recent developments have resulted in improved molecular sieves with higher absorption
capacity and more resistance to degradation. The latest modeling techniques allow better
optimization of design and operation. Our research work has shown that deactivation is mainly
due to a combination of two effects: (a) coke formation in the sieve and (b) caking due to
hydrothermal instability of the sieve. Coke reduces the maximum water adsorption capacity,
while caking leads to irreversible loss of drying capacity due to an increased residual water load
after regeneration. With our specific knowledge on both the adsorption step and the regeneration
step and the understanding of the deactivation mechanisms, we can optimize the operation of
these units to be more cost effective.
2.4.5 MERCURY REMOVAL
Mercury removal is normally done with a fixed bed adsorption step. Commonly used adsorbents
are sulphur impregnated carbons, in which the mercury reacts with sulphur to form the stable
mercuric sulphide. A standard molecular sieve will also absorb Hg but regeneration is
impossible. An alternative approach is the silver-impregnated molecular sieve. In principle this
molecular sieve can be regenerated, however the release of mercury from the molecular sieve
bed would require dedicated material selections in the regeneration gas treating section.
Integration of this Hg removal bed with the dehydration step is claimed to be possible. Usually
the preferred line-up has a simple dedicated mercury removal step (non-regenerative).
The position of the mercury removal unit in the treating section depends on feed gas
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composition, the material from which it is constructed, and the water content of the gas. The
mass transfer zone of the bed will be long at high water contents.
In the area of mercury removal recent progress has mainly been in the detection and speciation of
the different types of mercury. The current detection limit is 0.002-0.003 microgram/Nm3, which
is an order of magnitude lower than some years ago. Generally mercury removal units remove
the metallic mercury to below this detection limit.
2.4.6 DEVELOPMENTS IN PRE-TREATMENT
Membrane separation is based on thin barriers which allow preferential passage of components
to separate multi-component feeds. The driving force for permeation is the difference in partial
pressure between the feed gas and the permeate side of the membrane. Selectivity is achieved by
differences is permeation rates. Membrane units for natural gas processing are commercially
being used for CO2 / H2O removal to pipeline specifications, production of CO2 for Enhanced
Oil Recovery (EOR), unloading of existing treating plants, concentration of natural gas liquids.
The use of membranes in large volume natural gas applications for e.g. CO2 removal is still
restricted by the relatively high hydrocarbon losses and the fact that membranes do not have the
same economy of scale as many other processes due to their modular nature. Current
developments are therefore in improved permeance, reducing the required membrane area, and in
improved CH4/CO2 selectivity to further reduce the hydrocarbon losses with the permeate.
Inorganic membranes are an example of recent developments in this area.
Membranes can be economically used in the bulk CO2 removal step for natural gases containing
high concentrations of CO2. Amine processes using partial flash regeneration, such as Sulfinol-M
or MDEA, are the most economical solution for large volumes of natural gas containing less than
about 15 mol% CO2. Above 15 mol%, a bulk CO2 removal step upstream of the amine unit can
be attractive. Membranes can also be attractive for debottlenecking of existing CO2 removal
plants, as long as the permeate can be used as fuel.
Another area of interest is the use of membrane technology for LNG floaters, where movement
can be significant. A disadvantage of conventional technology is that the internals, such as acid
gas absorber trays and packing are sensitive to movements. Several research institutes, such as
GRI (USA) and TNO (Netherlands), are developing membrane alternatives for absorber trays,
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which are less sensitive to movement. An added advantage of the membrane contactor is the
reduction of heavy hydrocarbon co-absorption, while the absence of direct gas-solvent contact
removes the risk of foaming.
Up until recently the levels of CO2 and sulphur encountered in most LNG developments have
allowed a fairly open selection of solvent based pre-treatment technology although preference
has most often been given to well proven technologies. However with increased sulphur levels,
mercaptans and more extreme operating requirements the available choices for a cost effective
integrated treating package narrow dramatically. Use of the Shell Sulfinol technology can be the
decidedly more attractive option in these cases. It is critical that each new gas development
undergo a rigorous selection study to identify the most cost effective and fit for purpose treating
package.
2.5 CONVERSION OF NATURAL GAS TO POWER
A gas power station turns the chemical energy into electrical energy that can be used in homes
and businesses. Figure 1 below is used to explain the stages of conversion:
Natural gas (1) is pumped into the gas turbine (2), where it is mixed with air (3) and burned,
converting its chemical energy into heat energy. As well as heat, burning natural gas produces a
mixture of gases called the combustion gas. The heat makes the combustion gas expand. In the
enclosed gas turbine, this causes a build-up of pressure.
The pressure drives the combustion gas over the blades of the gas turbine, causing it to spin,
converting some of the heat energy into mechanical energy. A shaft connects the gas turbine to
the gas turbine generator (4), so when the turbine spins, the generator does too. The generator
uses an electromagnetic field to convert this mechanical energy into electrical energy.
After passing through the gas turbine, the still-hot combustion gas is piped to the heat recovery
steam generator (5). Here it is used to heat pipes full of water, turning the water to steam, before
escaping through the exhaust stack (6). Natural gas burns very cleanly, but the stack is still built
tall so that the exhaust gas plume (7) can disperse before it touches the ground. This ensures that
it does not affect the quality of the air around the station.
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The hot steam expands in the pipes, so when it emerges it is under high pressure. These high-
pressure steam jets spin the steam turbine (8), just like the combustion gas spins the gas turbine.
The steam turbine is connected by a shaft to the steam turbine generator (9), which converts the
turbine‟s mechanical energy into electrical energy.
After passing through the turbine, the steam comes into contact with pipes full of cold water. In
coastal stations this water is pumped straight from the sea (10 and 11). The cold pipes cool the
steam so that it condenses back into water. It is then piped back to the heat recovery steam
generator to be reused.
Finally, a transformer converts the electrical energy from the generator to a high voltage. The
national grid uses high voltages to transmit electricity efficiently through the power lines (12) to
the homes and businesses that need it (13). Here, other transformers reduce the voltage back
down to a usable level. (http://www.edfenergy.com/energyfuture/generation-gas).
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Fig 1: Stages showing the conversion of natural gas to electrical power
2.6 PROCESSING OF NATURAL GAS TO USEFUL PRODUCTS
2.6.1 EQUIPMENT USED AND DESCRIPTION
The processing of wellhead natural gas into pipeline-quality dry natural gas can be quite
complex and usually involves several processes. Most often, the number of gas treatment
steps and the type of techniques used in the process of creating pipeline-quality natural gas
depends on the source and makeup of the wellhead production stream. A typical natural
gas processing plant whose simplified schematic representation shown in Fig. 2 consists
Fig 2: Simplified schematic representation of a gas processing plant (Tobin J., Shambaugh
P. et al. 2006).
mainly of the following processes: (i) gas oil separator (treatment unit); (ii) condensate
separator; (iii) dehydrator; (iv) acid gas removal unit; (v) nitrogen extractor or Nitrogen
rejection unit (NRU) and (vi) fractionator.
Brief descriptions about the major unit operations are provided as follows:
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Gas-oil separators: are used to separate the gas stream and the crude oil at the top and
bottom part of the cylindrical shell respectively by the action of pressure at the wellhead
where gravity separates the gas hydrocarbons from the heavier oil.
Condensate separators: are used to remove condensates from the gas stream by
mechanical separators at the wellhead. In condensate treatment section, two main
operations, namely water washing and condensate stabilization are performed. Based on
the quality of the associated water, the condensate may require water wash to remove
salts and additives (Tobin J., Shambaugh P. et al. 2006).
Dehydrators: are used to remove water vapor using dehydration process so that the
natural gas will be free from the formation of hydrates, corrosion problem and dew point.
In this treatment, process of absorption using ethylene glycol is used to remove water and
other particles from the feed stream. As another option, adsorption process can also be
used for water removal using dry-bed dehydration towers (Tobin J., Shambaugh P. et al.
2006).
Acid gas removal units: are used to remove contaminates in the dry gas such as CO2,
H2S,some remaining water vapor, inert gases such as helium, and oxygen. The use of
alkanolamines or Benfield solution processes is mostly common to absorb CO2 and H2S
from the feed gas (Tobin J., Shambaugh P. et al. 2006).
Nitrogen extractor or Nitrogen rejection unit: are used to remove nitrogen from the
stream using two common ways. In the first type, nitrogen is cryogenically separated
from the gas stream by the difference in their boiling point. In the second type, separation
of methane from nitrogen takes place using physical absorption process. Usually
regeneration is done by reducing the pressure. If there were trace amounts of inert gases
like Helium then pressure swing adsorption unit can be used to extract them from the gas
stream (Tobin J., Shambaugh P. et al. 2006).
Demethanizer: are used to separate methane from NGLs using cryogenic processing or
absorption techniques. The demethanization process can take place in the plant or as
nitrogen extraction process. As compared to absorption method, the cryogenic method is
more efficient for the lighter liquids separation, such as ethane (Tobin J., Shambaugh P.
et al. 2006).
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Fractionators: are used to separate the NGLs present in the gas stream by varying the
volatility of the hydrocarbons present in the stream. In fractionation, the NGLs after the
demethanizer is subjected to rise through towers and heated to increase the temperature
of the gas stream in stages, assisting the vapor and liquid phases thoroughly contacted,
allowing the components to vaporize and condense easily and separate and flow into
specific holding tanks (Tobin J., Shambaugh P. et al. 2006).
2.7 TECHNOLOGIES IMPLORED
The technologies that are widely used to treat the natural gas include absorption processes,
adsorption processes, cryogenic condensation and membranes. In this review, we shall discuss
the cryogenic condensation technique. Comparative to the other natural gas separation
techniques, the membrane process is a viable energy-saving alternate gas separation since it does
not require any phase transformation. All the processes except membrane separation involves a
change in the state of phase of the penetrant specious, where the desired penetrant is selectively
transferred from gaseous state to liquid or solid state (Rojey 1997). Moreover, the necessary
process equipment for membrane separation is very simple with no moving parts, compact,
relatively easy to operate and control, and also easy to scale-up (Stern 1994).
The technologies and their improvement have been developed over the years to treat certain
types of gas with the aim of optimizing capital cost and operating cost, meet gas specifications
and environmental purposes (Ebenezer and Gudmunsson 2006).
2.7.1 PROCESS SELECTION FACTORS
The processes that are used to remove acid gas are broad and the existing technologies are
many that effective selection of process becomes a critical concern. This is because each of
the processes has their own advantages and limitations relatives to others. Although
common decisions in selecting an acid gas removal process can generally be simplified,
factors such as nature and amount of contaminants in the feed gas, the amount of every
contaminants present in feed gas and the targeted removal capacity, amount of hydrocarbon
in the gas, pipeline specification, capital and operating cost, amount of gas to be processed,
desired selectivity, conditions at which the feed gas is available for processing are the major
factors that should also be considered (Dortmundt and Doshi 1999).
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2.8 CRYOGENIC PROCESS
2.8.1 BASIC SEPARATION PRINCIPLE FOR CRYOGENIC PROCESS
Cryogenic separation (also known as low temperature distillation) uses a very low
temperature (-73.300C) for purifying gas mixtures in the separation process (Ebenezer and
Gudmunsson 2006).
The major industrial application of low-temperature processes involves the separation and
purification of gases. Much of the commercial oxygen and nitrogen, and all the neon, argon,
krypton, and xenon, are obtained by the distillation of liquid air (Meyers 2001).
Commercial helium is separated from helium-bearing natural gas by a well-established low
temperature process. Cryogenics has also been used commercially to separate hydrogen
from various sources of impure hydrogen (Meyers 2001).
The cryogenic method is better at extraction of the lighter liquids, such as ethane, than is the
alternative absorption method. Essentially, cryogenic processing consists of lowering the
temperature of the gas stream to around (-84.440C). While there are several ways to perform
this function the turbo expander process is most effective, using external refrigerants to chill
the gas stream. The quick drop in temperature that the expander is capable of producing
condenses the hydrocarbons in the gas stream, but maintains methane in its gaseous form
(Tobin J., Shambaugh P. et al. 2006).
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Table 1: Overall comparison of natural gas purification technologies
2.9 TECHNICAL AND ECONOMIC IMPLICATION OF NATURAL GAS
PROCESSING
With the 10th largest gas reserves in the world, the largest known resource in Nigeria is Natural
Gas. The country‟s reserve estimates of 110 trillion standard cubic feet of gas do not take
account of the reserves in the deep water offshore basin which has already recorded a few world
class oil discoveries in its early period of exploration. Indeed, gas is largely produced in Nigeria
in association with oil. Paradoxically, the country is not regarded as a major gas producing
nation in view of the fact that up to 75% of its daily production is being flared – the latest figures
estimates the flaring levels as somewhere between 180,000 and 257,000 barrels equivalent of
crude oil per day. At an annual carbon emission of over 35 million metric tonnes, this is a world
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record contribution to the depletion of the ozone layer and continues to generate an outcry both
locally and in foreign environmental circles. Nigeria has been under sustained pressure from
foreign environmental lobby groups over the years to respect its various treaty commitments to
reduce these phenomenal levels of emission of environmental hazardous substances. More
recently, it entered into The Kyoto Protocol which has placed more responsibilities on it to
reduce the flaring levels and also provides for Certified Emission Credits as a carrot to encourage
gas utilization. Also, continued environmental degradation from flash gas fires, acid rain and oil
spills has engendered a growing awareness in the host communities of the Niger Delta region of
environmental issues and rights. Inevitably, Nigeria is now witness to Green peace– scale sit-ins,
disruptions and sabotage of oil and gas installations by restive youths. If the situation persists,
mass tort actions will almost certainly follow.
Nigeria‟s competitive advantage as a major gas resource owning nation was lost to other gas
producing nations because the relative long distance of the country to the main gas markets
implied a high transportation cost for its gas. Also, there were several other institutional
bottlenecks affecting the investment flows required to accelerate the development of the sector.
These include: the absence of a formal gas policy to address the interests of all stakeholders in
the sector, a regulated gas price for domestic sales, inadequate infrastructure for transmission of
gas locally, a limited domestic market and a tax regime that was more designed for crude oil
exploration and development.
2.9.1 FLARING OF NATURAL GAS
Nigeria flares its natural gas chiefly because its oil fields lack the infrastructure to produce and
market associated natural gas. According to the National Oceanic and Atmospheric
Administration (NOAA), Nigeria flared 593 Bscf of natural gas in 2007, which, according to
NNPC, cost the country US$ 1.46 billion in lost revenue. Figure 2 shows the volume of gas
flared in 2007 by the top 9 countries in the world. The government of Nigeria has been working
to end natural gas flaring for several years but the deadline to implement the policies and fine oil
companies has been repeatedly postponed with some analysts pushing the date as far forward as
2012. In 2009, the Nigerian government developed a Gas Master Plan that would promote new
gas fired power plants to help reduce gas flaring and provide much-needed electricity generation.
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(EIA, 2010). Gas flaring is generally discouraged as it releases toxic components into the
atmosphere and contributes to climate change. The World Bank reported in 2004 that, "Nigeria
currently flares 75% of the associated gas it produces. Gas flaring releases large amounts of
methane, which has a high global warming potential. Gas flares have potentially harmful effects
on the health and livelihood of the communities in their vicinity, as they release a variety of
poisonous chemicals. Humans exposed to such substances can suffer from a variety of
respiratory problems. The international community, the Nigerian government, and the oil
corporations seem in agreement that gas flaring needs to be curtailed but efforts have been
limited over the years (Wikipedia, 2010).
The Nigerian natural gas sector is also affected by the security issues in the Niger Delta. Projects
are often delayed or shut-in as a result of sabotage, bunkering, and general insecurity. Most
recently, the Escravos Gas to Liquids (GTL) project was delayed until 2012 (from 2010 earlier
scheduled).
Fig 3: Top natural gas flares in the world
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2.9.2 NIGERIA LEGISLATION IN FAVOUR OF NATURAL GAS UTILIZATION
Some legislations have recently come on board to encourage more gas utilization opportunities
which would finally bring to an end the era of gas flaring. These legislations are geared towards
providing the needed incentives such as tax breaks for the International Oil companies (IOC) , to
motivate them in speeding up the natural gas utilization projects. These legislations include the
Nigerian Petroleum Industry Bill and the Nigerian Gas Master Plan.
Nigerian Petroleum Industry Bill In order to remedy some of problems of associated
with the utilization of Natural gas and oil, the Nigerian government is currently debating
a Petroleum Industry Bill (PIB) that is designed to reform the entire hydrocarbon sector.
Parts of the PIB have recently been made into law while the Bill in its entirety continues
to be debated by the National Assembly (Thisdayonline, 2010).
Nigeria Gas Master Plan With estimated reserves of 184Tscf, Nigeria, which is the
world‟s 7th largest natural gas producer, has flared its gas heavily in the past due to a
non-existent domestic gas market and underdeveloped infrastructure. With the emergence
of liquefied natural gas and natural gas liquid exports this has been reduced to
approximately 30 to 35 percent, or just less than 2.5 Bscf/day which is still a fraction of
its available huge reserves. Gas exports now contribute billions to government revenues,
with the majority coming through the Nigeria Liquefied Natural Gas Limited‟s project in
Bonny Island in the Niger Delta. Nigeria LNG is a joint venture between the Nigerian
National Petroleum Corporation, Shell, Total LNG Nigeria Limited and Eni.
(Thisafricaonline, 2010). Efforts to address the issue of infrastructure were put into action
when in February 2008 the Nigerian government announced a comprehensive new “Gas
Master plan” that seeks to improve supply to a domestic market that has become a
feasible destination for gas in recent years, boost production for exports and provide
much needed energy to the power sector. However, progress has been slow due to the
issue of pricing and absence of a clear legal and regulatory framework. Part of the new
gas policy would oblige oil producers to sell increased amounts of gas to the domestic
sector at prices that are a fraction of international export markets. Oil producers are
reluctant to comply with such a request, as it would effectively force them to lose money
(Onyeukwu, 2010).
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2.10 NATURAL GAS UTILIZATION OPTIONS.
Gas utilization entails putting natural gas, which has severally been regarded as a waste in
Nigeria, into economic and environment use. The utilization options employed worldwide
includes;
1. Pipeline Transportation: this approach to utilizing gas has been in existence for long
and still remains a significant mechanism for gas transportation to markets. Existing
routes in Nigeria include the West African Gas Pipeline, WAGP and the Trans
Saharan Gas Network, TSGP.
2. HVDC Light: Gas-to-wire project under which gas is used to generate electricity,
then converted to High Voltage Direct Current for long distance transmission to the
market (Varghese, 2003).
3. Compressed Natural Gas, CNG; CNG can be made by compressing natural gas
(which is mainly composed of methane), to less than 1% of the volume it occupies at
standard atmospheric pressure. It is stored and distributed in hard containers at a
pressure of 200- 248 bar, usually in cylindrical or spherical containers (Wikipedia,
2010).
4. Hydrate Transportation; A new technology which involves conversion of natural
gas to hydrates before transporting to markets (Varghese, 2003).
5. Liquefied Natural Gas, LNG; LNG is natural gas that has been cooled to the point
that it condenses to a liquid, which occurs at a temperature of about -2560F (-161
0F)
at atmospheric pressure. Liquefaction reduces the volume of gas by as much as 600
times thus making it more economical to store natural gas where other forms of
storage do not exist, and to transport gas over long distances for which pipelines are
too expensive or other constraints exist (CEE, 2006).
6. Gas to Liquid, GTL; Gas to liquids (GTL) is a refinery process to convert natural
gas or other gaseous hydrocarbons into longer-chain hydrocarbons such as gasoline or
diesel fuel (Wikipedia, 2010). GTL technology generally refers to the chemical
conversion of natural gas into readily transportable liquids such as methanol or
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conventional petroleum refinery type distillate fuels (Chinenye et al, 2007). Methane-
rich gases are converted into liquid synthetic fuels either via direct conversion or via
syngas as an intermediate, for example using the Fischer Tropsch or Mobil processes.
It is an emerging technology which involve chemical transformation of natural gas,
either into synthetic fuels (syncrude, diesel, kerosene, etc) or chemicals (methanol,
DME, etc.) (Balogun and Onyekonwu, 2009).
7. Enhanced Oil Recovery(EOR); EOR is the third stage of hydrocarbon production
proceeding primary and secondary recovery, during which sophisticated techniques
that alter the original properties of the oil are used. Enhanced oil recovery can begin
after a secondary recovery process or at any time during the productive life of an oil
reservoir. Its purpose is not only to restore formation pressure, but also to improve oil
displacement or fluid flow in the reservoir (Schlumberger, 2010). Some EOR
processes utilize natural gas for enhanced recovery of oil, e.g. miscible gas injection.
8. Natural Gas liquids(NGL); Generally such liquids consist of propane and heavier
hydrocarbons and are commonly referred to as lease condensate, natural gasoline, and
liquefied petroleum gases.(EIA, 2010).When a wet gas gets to the surface, it forms a
liquid which constitute the NGL (Oligney and Economides, 2002).
9. Liquefied Petroleum Gas, LPG; LPG has long been confused with propane. But it
is in fact predominantly a mixture of propane and butane in a liquid state at room
temperatures when under moderate pressures of less than 200 psig (CEE, 2006).
10. Underground Storage; this is another utilization option when natural gas utility is to
be deferred for future use by injecting into underground storages. This gas resource
can be accessed for later use when it is convenient (Atoyebi, 2010).
2.11 STATUS OF NIGERIA IN NATURAL GAS UTILIZATION
There are two potential markets for Nigerian Natural gas: domestic markets and foreign or export
markets. Domestic markets include power generation, cement industry, Iron and Steel Industries,
Fertilizer Industry, Petrochemicals, etc. Export includes Natural gas as LNG, pipeline export,
NGL, etc. The National Gas Company (NGC) is responsible for local utilization of natural gas. A
large potential market exists for investors in this area. Domestic gas demand is about 400 million
cubic feet a day (400 MMscf/d), which is very low compared to the size of Nigeria‟s population
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and its gas resources. The domestic market is limited by the low level of industrialization and the
inadequacy of the gas transmission and distribution infrastructure. The power sector currently
accounts for almost 90% of domestic gas sales (CEE, 2006). NNPC and other major E & P
operators are currently embarking on several gas utilization projects for export. The major
existing and future expected projects include the Gas liquefaction project, Gas to liquid project,
Gas transportation by pipeline project, etc. These utilization strategies, both domestic and foreign
are discussed in details below:
1. The LNG (liquefied natural gas) facility on Bonny Island was completed in September
1999 (Train 1 and 2). The facility processes 252.4 Bscf of LNG annually. Initially, the
facility is to be supplied from dedicated non associated gas fields, but within a few years
it is anticipated that half of the input gas will consist of associated (currently flared) gas.
Construction of a third LNG production train, with an annual capacity of 130.6 Bscf, was
completed and operational in December of 2002. The third LNG train increased NLNG's
overall LNG processing capacity to 383 Bscf per year. (CEE, 2006). Trains 4 and 5, or
"NLNGPlus Project", were developed by Halliburton and KBR in 2005. The plant has an
overall production capacity of 16.8 million tons per year (MMT/y) of LNG, 2 MMT/y of
LPG, and 1 million tons of condensate processing 1,334 MMscf/d of gas. This will bring
the overall capacity of the five trains to 2,810 MMscf/d of gas intake. Additionally, a
sixth train has also commenced production (NLNG, 2010). The non-associated producing
fields include Obite, Obiafu and Soku fields respectively. It is expected that flaring will
be substantially reduced following the immense investment in this project, in addition to
the expected huge returns (NAPIMS, 2006).
2. Brass LNG Brass LNG was incorporated in 2004 as a company and four stakeholders in
2006 signed the Shareholders Agreement for the Brass LNG Project. The shareholders
were Nigerian National Petroleum Corporation (NNPC), ENI International, Phillips
(Brass) Limited (an affiliate of ConocoPhillips) and Brass Holdings Company Limited -
an affiliate of TotalFinaElf (LNGpedia, 2005). The financial investment decision is
planned for the first quarter of 2011 with a total capital cost estimate of $15 billion
(LNGWorld, 2005).
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3. Escravos Gas Project Escravos Gas Project (EGP). EGP 1, the first major gas project to
gather and process associated natural gas in Nigeria, came on stream in 1997. The
project‟s second phase – extending capacity to 285 MMscf/d – began operations in 2000.
A planned Phase 3 will process up to 400 MMscf/d. The completed project will export
40,000 barrels per day of liquefied petroleum gas and condensate. NGLs are stripped for
export and the remaining gas is currently used domestically. The EGP-3 will process an
additional 400 MMscf/d of gas from ChevronTexaco's northern offshore fields
(Allafricanews, 2010).
4. Escravos Gas-to-Liquids; Chevron Nigeria Ltd. and the Nigeria National Petroleum
Corp. are constructing a 33,000-barrel-per-day gas-to-liquids plant in Escravos, Nigeria,
to convert natural gas into clean transportation fuels. Facility construction is under way.
The new facility is expected to convert 325 MMscf of natural gas into 33,000 barrels per
day of GTL diesel fuels, GTL naphtha and liquefied petroleum gas (Chevron, 2010). The
GTL plant is expected to cost $6 billion overall and to become operational by 2012
(Chevron, 2010).
5. Olokola LNG Project; Chevron is participating in development of the proposed Olokola
LNG Project, which includes plans for a 4-train natural gas liquefaction facility and
marine terminal located northwest of Escravos. The LNG would be marketed to the
Atlantic basin (Chevron, 2005). The contract was awarded to Delta Afrik – an indigenous
company at the cost of $14.6 million by partners, the NNPC, Chevron and recently, Shell.
The project will generate foreign exchange through export of LNG; produce 300,000
barrels a day of Liquefied Petroleum Gas (LPG) and condensates, which will be sold as
by-products. The initial gas would come from Shell and Chevron operated joint ventures,
approximately 1 Bscf/day of gas (African oil Journal, 2007).
6. Oso NGL Project MOBIL JV NGL plant located at its OSO field in the south-eastern
part (Akwa Ibom) of Nigeria started production for export during the third quarter of
1998. The Oso Phase 2 Project is to provide additional gas make-up for the OSO NGL as
well as maintain condensate production at the expected plateau (NAPIMS, 2005).
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7. Belema Gas Injection project SHELL JV Belema Gas Injection project is aimed at
reducing flares in five flow stations by reinjecting some of the gas, some for gas lifting,
and some for use as fuel by local industries and the excess for backing out Non-
Associated Gas, NAG, that is currently used to meet various existing contractual
obligations. The contracts for the execution of the Engineering, Procurement and
Construction (EPC) and gathering pipelines are still in the early stages of execution.
About 80 MMscf/d of gas is been utilized (National Petroleum Investment Management
Services (NAPIMS, 2006).
8. The West African Gas Pipeline Project (WAGP) This project run by the parties in The
Shell Petroleum Development Company of Nigeria (SPDC) Joint Venture is owned by
West African Gas Pipeline Company Limited (WAGPCo), a consortium of Chevron
(36.7%), NNPC (25%), Royal Dutch Shell (18%), and the state owned companies in
Ghana, Benin and Togo. Shell is expected to supply half of the initially required gas
required (Shell, 2010). The $924-million World Bank project will traverse 758km (474
mile) both on and offshore to its final planned terminus at Tokoradi in Ghana shown in
Figure 2.5. The diameter of the pipeline is 18” with a maximum discharge of 5 Bscm per
year (176 Bscf per year) (Wikipedia, 2010). Initial capacity estimate of 200 million cubic
feet per day (MMscf/d), would eventually reach full capacity of 450 MMscf/d. (EIA,
2010).
9. Trans-Saharan Gas Pipeline Nigeria underlined its determination to penetrate the
European gas market when it signed preliminary agreements with Algeria on a planned
Trans-Saharan Pipeline running through the North African country into Europe. The
project would seek to connect the Nigerian gas field with that of Algeria, to the European
market. The 2,565-mile (4,128-km) pipeline would carry natural gas from oil fields in
Nigeria's Delta region to Algeria's Beni Saf export terminal on the Mediterranean. In
2009 the NNPC signed a memorandum of understanding (MoU) with Sonatrach, the
Algerian national oil company. Several national and international companies have shown
interest in the $ 12.2 billion project including Total and Gazprom (EIA, 2010).
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10. The Gbaran-Ubie Integrated Oil and Power the Gbaran-Ubie project aims to further
develop Nigeria‟s oil and gas resources and will ensure government targets to reduce gas
flaring. The project which is fully operational will be capable of producing 1 billion
standard cubic feet of gas a day (scf/d), equivalent to about a quarter of the gas currently
produced for export and domestic use in Nigeria. It will also produce as much as 70,000
barrels of oil per day (Shell, 2010).
11. The Afam Integrated Gas and Power Project the Afam integrated gas and power
project is owned by Shell Petroleum Development Company (SPDC). It consists of the
Afam VI power plant and the Okoloma gas plant in Rivers State, the Niger Delta. When
fully operational, this integrated project will increase Nigeria‟s power supply
by about 20% of current operational capacity and the country‟s domestic gas supply by
some 20%. The 650-megawatt (MW) combined-cycle power plant is an advanced design
that requires only two thirds of the gas needed by many of Nigeria‟s existing power
plants to generate each unit of electricity. Afam VI‟s gas turbines generate up to 450MW
of power. Waste heat from the plant is then used to generate a further 200 MW of very
low emission electricity (Shell, 2010)
12. .Expansion of domestic gas distribution network several distribution schemes are
planned to help promote Nigerian consumption of natural gas. The proposed $745-
million Ajaokuta-Abuja-Kaduna pipeline will deliver gas to central and northern Nigeria,
while the proposed $552-million, Aba-Enugu-Gboko pipeline will deliver natural gas to
portions of eastern Nigeria. The Lagos State government and Gaslink Nigeria Limited
(Gaslink), a local gas distribution company, are developing a pilot program to deliver
natural gas to nine residential neighbour hoods in the state. Gaslink recently began
supplying gas to nearly 30 industrial customers in Lagos Ikeja industrial district (CEE,
2006).
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2.12 SOURCES OF NATURAL GAS IN NIGERIA
Nigeria has more than 250 oil and gas fields, with about 2,600 producing oil wells and a total oil
production of about 2 million barrels per day (MMSTB/d) (World Energy, 2004). In 2007,
Nigeria produced 1,204 billion cubic feet (Bscf) of natural gas, while consuming 456 Bscf
(Energy Information Administration, 2010). All the accumulations of Natural Gas of
commercial extent have been proven to exist in the Niger Delta region of Nigeria. The raw gas
comes either as associated or non-associated gas. Associated or dissolved gas is found with the
crude oil. This gas can exist dissolved in the crude oil (dissolved gas) or as a free gas in contact
with the crude oil (sometimes called gas cap gas). Natural gas from gas and condensate wells, in
which there is little or no oil, is termed non associated gas (Naturalgas, 2010). All the crude oil
reservoirs contain dissolved gas and may or may not contain free gas. Non associated gas is
found in a reservoir that contains a minimal quantity of crude oil (Guo et al, 2005). The
prominent fields with either associated or non-associated natural gas accumulations are
described the following section;
Bonga Field; This is located in License block OPL 212 off the Nigerian Coast, which
has now been renamed as OML 118 in February 2000. The field covers approximately
60km2 in an average water depth of 1,000metres (3,300 ft). The field produces both
crude oil and natural gas; the crude oil is offloaded to tankers while the gas is piped back
to Bonny in Nigeria where it is exported via an LNG plant. The field contains
approximately 6,000 MMBOE. The daily production of oil stands at 202,000 BOPD
(2006) and gas production is 150MMscf/d. The estimated oil and gas in place stood at
1470 MMbbl and 965 Bscf (Shell, 2010).
Akpo Field; Situated offshore Nigeria in 1400m of water, Akpo field, which is operated
by Total with 24% interest, has a daily production of 175,000 B/D of condensate and
320 MMSCF/D of gas for onward shipment to the NLNG plant at Bonny. The
recoverable reserve stands at 620 MMbbl of condensate with density of 53 OAPI
(Wikipedia, 2010).
Oso Field; About 89 km south-west of Mobil's Qua Iboe terminal and 67 km from the
Bonny island gas processing system, Oso is a giant gas field by African standards now
producing 110,000 bbl/d. The field has had enough reserves to recover at least 500m
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barrels of condensate in a 20-year production period and to still have a deposit of about
3,500 Bscf. Mobil can recover liquids, including butane (C4H10) and propane (C3H8)
from the crude oil. As the gas is forced to the surface, it cools and takes the form of
condensate, having the qualities of a very light, almost sulphur-free crude oil. Gas
associated with condensates is then re-injected into Oso for pressure maintenance
(Online library, 2010).
These fields are located in the Niger Delta region of Nigeria which consists of seven states
including Bayelsa, Delta, Abia, Akwa Ibom, Cross River, Edo, Ondo and Imo (Wikipedia,
2010).
Fig 4: The Niger Delta region of Nigeria (EIA, 2010).
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CHAPTER THREE
CONCLUSION AND RECOMMENDATION
3.1 CONCLUSION
Since 1995, significant progress has been made in the commercialization of natural gas
conversion technologies for the production of chemicals and synthetic fuels. In this report, we
update the state of the art in natural gas conversion technologies with a focus on cryogenic
condensation technique. Pollution and environmental implication of gas flaring was examined
and the utilization strategies for natural gas generally were listed. This is not exhaustive but will
serve as an integral in the best way of maximizing the use of natural gas.
3.2 RECOMMENDATION
Based on the findings made in this study, the following well considered recommendations are
vital for utilizing natural gas:
Employing the technologies suggested in the course of its treatment
Converting flared gas to other source of energy
Reducing the extent of pollution caused by flared gases in the state where the resource is
in abundance.
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BIBLIOGRAPHY
Bahadori, A., S. Mokhatab, et al. (2007). Rapidly estimating natural gas compressibility factor.
Journal of Natural Gas Chemistry, Vol. 16, No. 4, pp. 349-353
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