Natural gas is
an important energy source among other sources of fossil fuels. It is usually
produced saturated with water vapor under production conditions. The
dehydration of natural gas is very essential in the gas processing industry to
remove water vapor. Water vapor in natural gas stream, poses threat to process
facilities if the dew point temperature is not properly controlled. Dehydration of natural gas is the process removal of the
water that is associated with natural gases. The mixtures of water in natural
gas can cause the problems for the production operation, transportation,
storage and use of the gas. The four major methods of dehydration are
absorption, adsorption, gas permeation and refrigeration. The process of
dehydration by using TEG is absorption, involves the use of a liquid desiccant
to remove water content from the gas.
objective of this experiment is to carry out a simulation on TEG dehydration
unit using AspenHYSYS process software.
This is important in an FPSO since the removal of water from natural gas is
necessary before processing, and due to the fact that Natural gas from the
reservoir contains large amount of water which can cause several problems to
downstream processes and equipment. TEG was used because it has gained nearly
universal acceptance as the most cost effective of the glycols due to its
superior dew point depression, operating cost and operational reliability. The
composition of the natural gas has been provided on a water-free basis,
therefore to ensure water saturation it was mixed with water before entering
the first unit operation. The units involved in this simulation are;
Contractor, Regenerator, Valve, Component splitter, Cooler, Stripper and
Splitter, alongside with an adjust logical tool which was used to find the
point at which water is just formed (dew point with a temperature of -13.67Oc).
At the end of the converged simulation, 89.92 wt% methane was recovered at a
flow rate of 9177kg/hr. which might have resulted due to loss of some of the
gases at certain stage of the process.
Table of Contents
BACKGROUND OF STUDY
DEHYDRATION OF NATURAL GAS
STATEMENT OF THE PROBLEM
1.4 OBJECTIVES OF THE STUDY
The research question of this project is based on the
JUSTIFICATION OF THE STUDY
SCOPE/LIMITATION OF STUDY
IN OFFSHORE PRODUCTION
2.3.2 GAS TREATMENT
2.3.3 INORGANIC CONTENTS
2.3.4 OTHER CONTAMINANTS
2.3.6 LIQUEFACTION OF THE GAS
2.5.1 GAS HYDRATES
OF NATURAL GAS
2.6.1 DEHYDRATION OF NATURAL GAS
2.6.2 TYPES OF
DEHYDRATION OF NATURAL GAS
2.6.3 COMPARISON OF THE METHODS
2.6.4 GLYCOLS USED
2.7 DRY GAS
THE GLYCOL GAS DEHYDRATION PROCESS
2.8.2 TEG DEHYDRATION UNIT
2.8.3 DEHYDRATION BY USING TRIETHYLENE GLYCOL (TEG)
3.1 Materials used for
3.2 Component selected
for the simulation in Aspen Hysys
3.3 Fluid package used
(Thermodynamics property used).
3.4 Equipments used
3.5 Simulation procedure
RESULT AND DISCUSSION
Natural gas processing is a complex industrial
process designed to clean raw natural gas by separating impurities and various
non-methane hydrocarbons and fluids to process what is known as pipeline quality dry natural gas (^ Fact
sheet: Natural gas processing). Natural gas processing begins at the well head.
The composition of the raw natural gas extracted from producing wells depends
on the type, depth and location of the underground deposit and the geology of
the area. Oil and natural gas are often found together in the same reservoir.
The natural gas produced from oil wells is generally classified as associated-
dissolved, meaning that the natural gas is associated with or dissolved in
crude oil. Natural gas production absent any association with crude oil is
classified as “non-associated”.
Natural gas processing plants
purify raw natural gas by removing common contaminants such as water, carbon
dioxide (CO2 ) and hydrogen sulfide (H2s). Some of the
substances which contaminate natural gas have economic value and are further
processed or sold. A fully operational plant delivers pipeline-quality dry
natural gas that can be used as fuel by residential, commercial and industrial
consumers. The raw natural gas must be purified to meet the quality standard
specified by the major pipeline transmission and distribution companies. These
quality standards vary from pipeline to pipeline and are usually a function of
a pipeline system design and the markets that it serves. In general, the
standards specify that the natural gas:
within a specific range of heating value(caloric value) for example, in the
united states, it should be about 1035±5% BTU per cubic feet of the gas at 1
atmosphere and 600 (41 MJ ±5% per cubic meter of gas at 1 atmosphere
and 15.60 c).
delivered at or above a specified hydrocarbon dew point temperature (below
which some of the hydrocarbons in the gas might condense at pipeline pressure
forming liquid slugs that could damage the pipeline).
adjustment serves the reduction of the concentration of water and heavy
hydrocarbons in natural gas to such an extent that no condensation occurs
during ensuing transport in the pipelines.
free of particulate solids and liquids water to prevent erosion, corrosion or
other damages to the pipeline.
dehydrated of water vapor sufficiently to prevent the formation of methane
hydrate within the gas processing plant or subsequently within the sales gas
transmission pipeline. A typical water content specification in the U.S. is
that gas must contain no more seven pounds of water per million standard cubic
feet (MMSCF) of gas. (Prof. Jon Steiner Gudmundsson)
no more than trace amounts of components such as hydrogen sulfide, carbon
dioxide, mercaptans and nitrogen. The most common specification for hydrogen
sulfide content is 0.25 grain H2S per 100 cubic feet of gas, or
approximately 4 ppm. Specification for C02 typically limit the
content to no more than two or three percent.
mercury at less than detectable limits (approximately 0.001 ppb by volume)
primarily to avoid damaging equipment in the gas processing plant or the
pipeline transmission system from mercury amalgamation and embrittlement of
aluminum and other metals.
The natural gas product fed into the mainline gas transportation
system must meet specific quality
measures in order for the pipeline grid to operate properly. Natural gas
produced at the wellhead, which in most cases contains contaminants and natural
gas liquids, must be processed and cleaned, before it can be safely delivered
to the high-pressure, long-distance pipelines that transport the product to the
consumers. Natural gas that is not within certain specific gravities,
pressures, Btu content range, or water content levels will cause operational
problems, pipeline deterioration, or can even cause pipeline rupture. Gas
processing equipment, whether in the field or at processing/treatment plants,
assures that these tariff requirements can be met. While in most cases
processing facilities extract contaminants and heavy hydrocarbons from the gas
stream, in some cases they instead blend some heavy hydrocarbons into the gas
stream in order to
bring it within acceptable Btu levels. Natural gas processing begins at the
wellhead. The composition of the raw natural gas extracted from producing wells
depends on the type, depth, and location of the underground deposit and the
geology of the area. Oil and natural gas are often found together in the same
reservoir. Natural gas production absent any association with crude oil is
classified as “Non-associated”. Most natural gas production contains, to
varying degrees, small (two to eight carbons) hydrocarbon molecules in addition
to methane. Although they exist in a gaseous state at underground pressures,
these molecules will become liquid (condense) at normal atmospheric pressure.
Collectively, they are called condensates or natural gas liquids (NGLs).
Natural gas usually contains significant quantities
of water vapor. Changes in temperature and pressure condense this vapor
altering the physical state from gas to liquid to solid.A dehydration process is needed to eliminate water which may cause the
formation of hydrates. Hydrates form when a gas or liquid containing free water
experiences specific temperature/pressure conditions. Dehydration is the
removal of this water from the produced natural gas and is accomplished by
several methods. Among these is the use of ethylene glycol (glycol injection)
systems as an absorption mechanism to remove water and other solids from the
gas stream. Alternatively, adsorption dehydration may be used, utilizing
dry-bed dehydrators towers, which contain desiccants such as silica gel and
activated alumina, to perform the extraction.
In 1810, an
English scientist by the name John Dalton stated the total pressure of a gaseous
mixture is equal to the sum of the partial pressure of the components. This
statement, now known as Dalton’s law of partial pressure, allows us to compute
the maximum volume of water vapor that natural gas can hold for a given
temperature and pressure. The wet inlet gas temperature and supply pressure are
the most important factors in the accurate design of a gas dehydration system.
Without this basic information the sizing of an adequate dehydrator is
impossible. There are many other important pieces of design information
required to accurately size a dehydration system. These include pressures flow
rate and volumes.
All gases have the capacity to hold
water in a vapor state. This water vapor must be removed from the gas stream in
order to prevent the formation of solid ice like crystals called hydrates.
Hydrates can block pipelines, valves and other process equipment. The
dehydration of natural gas must begin at the source of the gas in order to
protect the transmission system.
The source of the gas moved through the transmission lines may be
producing wells or developed storage pools. Pipelines drips installed near well
heads and at strategic locations along gathering and trunk lines will eliminate
most of the free water lifted from the wells in the gas stream. Multi stage
separators can also be deployed to insure the reduction of free water that may
be present. Water vapor moved through the system must be reduced to acceptable
industry level. Typically, the allowable water content in gas transmission
lines ranges from 41b. to 7lb. per MMSCF.
Dehydration systems used in the natural
gas industry fall into four categories in principle:
Indirect cooling (Expander or Joule-Thomson valve)
Direct cooling: The ability of natural gas to contain water vapor decreases as
the temperature is lowered at constant pressure. During the cooling process,
the excess water in the vapor state becomes liquid and is removed from the
system. Natural gas containing less water vapor at low temperature is output
from the cooling unit. The gas dehydrated by cooling is still at its water dew
point unless the temperature is raised again or the pressure is decreased. It
is often a good practice that cooling is used in conjunction with other
dehydration processes. Glycol may be injected into the gas stream ahead of the
heat exchanger for instance to reach lower temperatures before expansion into a
low temperature separator.
Indirect cooling: Expansion is a second way of natural gas cooling. It can be
achieved by the expander or Joule-Thomson valve. These processes are
characterized by a temperature drop to remove condensed water to yield
dehydrated natural gas. The principal is the similar to the removal of humidity
from outside air as a result of air conditioning. Gas is forced through a
constriction called an expansion valve into space with a lower pressure. As a
gas expands, the average distance between molecules grows. Because of
intermolecular attractive forces, expansion causes an increase in the potential
energy of the gas. If no external work is extracted in the process and no heat
is transferred, the total energy of the gas remains the same. The increase in
potential energy thus implies a decrease in kinetic energy and therefore in
desiccant dehydration, also known as solid bed, utilizes the adsorption
principles for removing water vapor. Adsorbents used include silica gel (most
commonly used), molecular - 8 - sieve (common in natural gas vehicle dryers),
activated alumina and activated carbon. The wet gas enters into an inlet
separator to ensure removal of contaminants and free water. The gas stream is
then directed into an adsorption tower where the water is adsorbed by the
desiccant. When the adsorption tower approaches maximum loading, the gas stream
is automatically switched to another tower allowing the first tower to be
regenerated. Heating a portion of the mainstream gas flow and passing it
through the desiccant bed regenerates the loaded adsorbent bed. The
regeneration gas is typically heated in an indirect heater. The undersaturated
regeneration gas is then passed through the bed removing water and liquid
hydrocarbons. These liquid components have to be removing from gas for two main
reasons. First reason is present the water can allow natural gas hydrates
forming. Second reason is a lot of corrosive and aggressive compounds (H2S,
CO2) can be absorbed in this liquid phase. The regeneration gas
exits the top of the tower and is cooled most commonly with an air-cooled heat
exchanger. Condensed water and hydrocarbons are separated and the gas is
recycled back into the wet gas inlet for processing.
Absorption: The fourth method of dehydration utilizes liquid desiccant and it
is the most commonly used for dehydrating natural gas moved through
transmission lines. Method removes water from the gas stream by counter current
contact, in a tray type contactor tower, with tri-ethylene glycol (TEG).
Natural gas enters the unit at the bottom of the adsorber tower and rises
through the tower where it contacted with the TEG solution flowing downward
across bubble trays. Through the contact, the gas gives up its water vapor to
the TEG. The water laden TEG is circulated in a closed system, where the water
is boiled from the TEG. The regenerated TEG then is recirculated to the
Natural gas that comes from oil wells is not totally
pure but there are contaminants or mixtures in gas or typically termed
'associated gas’ like water vapor, hydrogen sulfide (H2S), carbon
dioxide, helium, nitrogen, and other. These mixtures in natural gas can cause
the problems for the production operation, transportation, storage and use of
the gas. One of those contaminants is water content. This water can result in
corrosion of pipeline and fittings in gas transmission systems and the
formation of ice or hydrates that causing flow restriction, with resulting
consequences in terms of plant operating efficiency.
This project work would seek to;
gas dehydration process when tri-ethylene glycol (TEG) is used as the
dehydrating agent using HYSYS.
tri-ethylene glycol (TEG) with other dehydrating agents
How is gas dehydration carried out on an
What is the best method to employ while
How can loss of tri-ethylene glycol be
All raw natural gas is fully saturated with water
vapor when produced from an underground reservoir. Because most of the water
vapor has to be removed from natural gas before it can be commercially
marketed, all natural gas is subjected to a dehydration process. This project
work discusses the types of glycols that may be used and the process used to re move water with glycol (TEG).
The project work involves the fabrication of the
dehydration unit on the Floating, production, storage and offloading vessel
(FPSO) and Simulation of the natural gas dehydration using the of Aspen hysys.
This work was limited due to financial constraint, difficulty arising from the
software used (hysys).
Aspen hysys software was used as a simulation tool
for the dehydration of the gas using triethylene glycol (TEG) as an absorbent
for the removal of water vapour.