NATURAL GAS

PROCESSES,
MODELING AND
SIMULATION

Dr Sourav Poddar
Department of Chemical Engineering
National Institute of Technology Warangal
Detailed Syllabus:
Gas Dehydration: Glycol Process: Operation, System Parameters,
Contactor Sizing and Stage Calculations, Graphical and Analytical
Methods. Regeneration. Solid Bed Absorption: Types of solid desiccants,
System Parameters, Operation and Design Sweetening: Acid Gases
Toxicity, Solid Bed Process , Absorbent Selection, Selection Variables
and Design , Physical & Chemical absorption Processes, Sulphur
Recovery Storage of Natural Gas: Pipeline Storage, Underground
Storage, Mined Caverns
Modeling and Simulation: Introduction, Absorber, Distillation Column,
Heat Exchanger, Regeneration unit, Simulation by software (Matlab and
Aspen Plus, etc.)
Reference Books:

1. Chi U.Ikoku, Natural Gas Production Engineering, John Wiley & Sons.1992.

2. James G Speight, Natural Gas –A Basic Hand Book, Gulf Publishing Company,
2007.

3. Sanjay Kumar, Gas Production Engineering, Gulf Publishing Company, Volume

4, 1987.

4. John M Campbell, Gas Conditioning & Processing Volume 2, Volume 3,

Volume 4 Campbell Petroleum Series.

5. Donald Katz, Hand Book of Natural Gas engineering, McGraw Hill, 1959.

6. LP Dake, Fundamentals of Reservoir Engineering, Elsevier, 1978.

7. Hussain K. Abdel-Aal, Mohammed Aggour, M.A. Fahim, Petroleum and Gas

field Processing,
Marcel Dekker, 2003.
 INTRODUCTION

What Is Natural Gas?

➢ Natural gas is a subcategory of petroleum that is a naturally

occurring, complex mixture of hydrocarbons, with a minor amount of
inorganic compounds.
Table 1-1 shows composition of a typical natural gas.
Natural Gas Value Chain
The conversion of natural gas into a liquid has been an elusive
objective for a long time. Some parts of the produced gas –
propane, butane, and the natural condensate, can be shipped as
LPG or natural gasoline. If it is available in sufficient quantity,
the ethane can be split out and converted into petrochemicals
(ethylene and its derivatives). The big question has always been
what to do with the methane.

The chart shows the overall picture for natural gas monetization
options. The methane, or C1, portion can be transported by
pipeline or by liquefaction and shipping, or it can be chemically
converted to a liquid as methanol or by using the Fischer-
Tropsch reaction.
Figure 1: Chart foe Natural Gas Value line
Table-1.2
 Gas Reserves in India

India has a bright long term natural gas supply outlook. Certified
reserves of over 28 BCM* on a deepwater block in the
Krishna/Godavari basin is a conservative figure with respect to
significant potential for future discoveries in the basin and the Bay of
Bengal. More than 9 big discoveries have been made in less than 3
years and a further multi-million deepwater exploration program was
kicked off recently.
The very first exploratory venture by RIL in this block has resulted in
world’s largest gas discovery for the year 2002. In addition, there is a
high probability of success based on the data available is expected for
the unexplored deeper targets. These targets are expected to yield new
discoveries and consequently the resources from the field are
expected to grow with time. It is anticipated that through sustained
exploratory drilling in the next few years, the reserves are likely to
increase and may range from 23 - 30 tcf**.

*Billion cubic metres of natural gas **trillion cubic feet

Miscellaneous Activities for New Opportunities to
Petroleum Specialists

➢ ONGC signed an agreement with L.N. Mittal group to form two

51:49 % joint venture companies - OMEL (ONGC Mittal Energy
Ltd) and OMESL (ONGC Mittal Energy Services Ltd) for
exploration, production and shipping activities abroad
➢ OMEL has entered into an MOU with Nigeria under which the
later will allocate deep water exploration blocks in Nigeria that
are expected to yield 32.5 million tones of oil every year for 25
years. The right of PSC has been obtained by offering Abuja a $
6 billion “capacity build up” package. OMEL will build or get
Indian companies to build power plants, railway system,
refining capacity and training institutes in Nigeria, in return of
equity oil
➢ ONGC Videsh will hold 50 % stake, Engineers India 25 %,
Indian Oil Corporation 15% and Oil India the remaining 10
% in the US $ 750 million refinery revamp and petroleum
products pipeline projects in Sudan.

➢ ONGC has offered 26 % partnership in to Coal India Ltd

(CIL) in its Underground Coal Gasification projects. CIL
is also likely to join ONGC in its CBM projects.

➢ ONGC board has approved setting up of a new company

Opal (ONGC Petro-additions Private Ltd) to implement the
C2-C3 extraction plant at Dahej from rich LNG to be
supplied by Petronet LNG Ltd.
➢ ONGC Videsh has signed a MOU with Ghana National Petroleum
Corporation GNPC) to study and evaluate data of Central basin
so as to enter an agreement for exploration, development and
production agreement.

➢ GAIL and EIL (Engineers India Ltd) have signed a MOU for gas
processing and transportation projects abroad.

➢ IOC (Indian Oil Corp) and STATOIL, Norway have formed into
a SPV (Special Purpose Vehicle) for acquisition of prospective
exploration acreage and producing properties. They have also
entered into a agreement for the formation of joint venture
SPV towards securing service business in oil and gas
industry internationally.
➢ ONGC Videsh and Norsk Hydro have signed a MOU under
which the companies will make opportunities available for
each other’s consideration on nonexclusive basis.

➢ ONGC has entered into an MOU with ENI for exchanging

information in a wide range of exploration opportunities in
India and overseas and be a strategic partner with state of
art technology, specially in deep water exploration and
development.

➢ OILEX of Australia has acquired 30 % stake in onshore

Cambay gas field in Gujarat from GSPC
➢ GAIL plans to set up a coal gasification plant of 2000 tonnes capacity
in Eastern India to produce three to four million cubic meters of syn-
gas per day using Shell Coal Gasification Process.

➢ ONGC has signed a MOU with Water and Power Consultancy

Services (WAPCS), a Government of India company, to address
deeper unexploited ground water in draught prone areas under
Project SARASWATI.

➢ GAIL and HPCL have entered into an agreement to jointly address

E&P and City Gas Projects. They will look for farm out opportunities
and bid for overseas E&P projects on the line of ONGC Videsh.
➢ India and Turkey have signed a MOU for cooperation in field of
oil and gas Indian and Turkish companies will cooperate in
bidding for NELP blocks and also in E&P, LNG, engineering
projects in third countries.

➢ GAIL has entered into an agreement with Ergo Exergy

Technologies Inc, Canada for ‘in-situ Lignite Gasification
technology for its project on Underground Coal Gasification in
Rajasthan.

➢ GAIL has signed a MOU with Arrow Energy, Australia and

Energy Infrastructure Group, Sweden for cooperation in
addressing CBM opportunities in India Australia and other
countries of mutual interest.
➢ ONGC has signed a MOU with Skochinsky Institute of Mining, Russia
for technical cooperation in underground coal gasification (UGC).
ONGC is also in process of signing MOU with Coal India, Neyeli Lignite
Corporation and GSPCL for cooperation in applying this technology in
various parts of India. The syn-gas produced during UGC comprises
methane, carbon monoxide and hydrogen and has lesser calorific value.

➢ ONGC has joined hands with GMDC (Gujrat Mineral Development

Corp) for UCG in Gujrat.

➢ ESSAR has drilled three wells to 1400 m depth in CB-ON-3 in North

Cambay Basin for CBM exploration. One of these wells has been
dewatered to produce CBM. The wells are planned to be on production
in February 2006.
➢ Reliance announced discovery of 3.76 tcf in place reserves
of coal bed methane gas in Sohagpur East and West blocks
in Madhya Pradesh.

➢ ONGC is presently testing 2 wells for coal bed methane gas.

Commercial production has taken place recently.

➢ Great Eastern Energy Corp Ltd (GEECL) has discovered

significant reserves of CBM in Raniganj coal field area in
West Bengal allotted to them on nomination basis before
CBM exploration rounds were started. Reserves estimated
by DGH are 1.385 tcf GEECL plans to drill 100 production
wells in the area and will soon start drilling of first 20 wells.
➢ ESSAR and Gardes Energy Services of USA have
formed a 50:50 joint venture to offer technology and
allied services for exploration and drilling for CBM
and oil/gas. The JV intends to bid for CBM and
oil/gas blocks in Russia, Kazakhstan, China, and
Turkey beside India.

➢ Cheveron will buy 29% interest in Reliance

Petroleum Ltd for nearly U$ 1.8 billion (₹ 8100
crores).

➢ Gas Hydrate: The first gas hydrate well KK-GH-01

has been spudded in Kerala-Konkan offshore in
water depth of 2674 m by research vessel JOIDES
Resolution 294 MW.
GAS PRODUCTION ENGINEERING FUNDAMENTALS
Introduction
The role of a production engineer is to maximize oil
and gas production in a cost-effective manner.

Fig. 4.1, shows a complete oil or gas production system

consists of a reservoir, well, flowline, separators, pumps, and
transportation pipelines. The reservoir supplies well-bore
with crude oil or gas.
 Figure 4.1 A sketch of a Oil or Gas production system.
_
Pwf = flowing bottom hole pressure p = average reservoir pressure
 Reservoir

Hydrocarbon accumulations in geological traps can be

classified as reservoir, field, and pool. A ‘‘reservoir’’ is a
porous and permeable underground formation containing an
individual bank of hydrocarbons confined by impermeable
rock or water barriers and is characterized by a single
natural pressure system. A ‘‘field’’ is an area that consists of
one or more reservoirs all related to the same structural
feature. A ‘‘pool’’ contains one or more reservoirs in isolated
structures.
Hydrocarbon accumulations are classified as oil, gas
condensate, and gas reservoirs. Reservoir Condition is
shown in Fig. 4.2
Figure 4.2a A typical hydrocarbon phase diagram.
An oil that is at pressure above its bubble point pressure is
called an “unsaturated oil” because it can dissolve more gas
at the given temperature.

An oil that is at its bubble point pressure is called a

“saturated oil” because it can dissolve no more gas at the
given temperature.

Single phase flow prevails in an undersaturated oil

reservoir, where as two-phase (liquid oil and free gas) flow
exists in a saturated oil reservoir.

The reservoirs at and above dew point are classified as

gas reservoirs.
 Gas Reservoirs

In general, if the reservoir temperature is above the critical

temperature of the hydrocarbon system, the reservoir is classified
as a natural gas reservoir. On the basis of their phase diagrams
and the prevailing reservoir conditions, natural gases can be
classified into four categories:
• Retrograde gas-condensate
• Near-critical gas-condensate
• Wet gas
• Dry gas
Retrograde gas-condensate reservoir: If the reservoir
temperature T lies between the critical temperature Tc and
cricondentherm* Tct of the reservoir fluid, the reservoir is
classified as a retrograde gas-condensate reservoir. This
category of gas reservoir is a unique type of hydrocarbon
accumulation in that the special thermodynamic behavior of
the reservoir fluid is the controlling factor in the development
and the depletion process of the reservoir. When the pressure
is decreased on these mixtures, instead of expanding (if a gas)
or vaporizing (if a liquid) as might be expected, they vaporize
instead of condensing. Consider that the initial condition of a
retrograde gas reservoir is represented by point 1 on the
pressure-temperature phase diagram of Figure 4.2b.

* The maximum temperature at which two phases can coexist.

Because the reservoir pressure is above the upper dew-point
pressure, the hydrocarbon system exists as a single phase
(i.e., vapor phase) in the reservoir. As the reservoir pressure
declines isothermally during production from the initial
pressure (point 1) to the upper dew-point pressure (point 2),
the attraction between the molecules of the light and heavy
components causes them to move further apart further
apart. As this occurs, attraction between the heavy
component molecules becomes more effective; thus, liquid
begins to condense.
Figure :4.2b A typical phase diagram of a retrograde system.
This retrograde condensation process continues with
decreasing pressure until the liquid dropout reaches its
maximum at point 3. Further reduction in pressure permits
the heavy molecules to commence the normal vaporization
process. This is the process whereby fewer gas molecules
strike the liquid surface and causes more molecules to leave
than enter the liquid phase. The vaporization process
continues until the reservoir pressure reaches the lower dew-
point pressure. This means that all the liquid that formed
must vaporize because the system is essentially all vapors at
the lower dew point. In most gas-condensate reservoirs, the
condensed liquid volume seldom exceeds more than 15%–
19% of the pore volume.
 This liquid saturation is not large enough to allow any liquid
flow. It should be recognized, however, that around the
wellbore where the pressure drop is high, enough liquid
dropout might accumulate to give two-phase flow of gas and
retrograde liquid. The associated physical characteristics of
this category are:

• Gas-oil ratios between 8,000 to 70,000 scf/STB*. Generally, the

gas-oil ratio for a condensate system increases with time due to
the liquid dropout and the loss of heavy components in the
liquid.
• Condensate gravity above 50° API
• Stock-tank liquid is usually water-white or slightly colored.
* standard cubic foot per stock tank barrel.
There is a fairly sharp dividing line between oils and
condensates from a compositional standpoint. Reservoir
fluids that contain heptanes and are heavier in
concentrations of more than 12.5 mol% are almost always
in the liquid phase in the reservoir. Oils have been
observed with heptanes and heavier concentrations as low
as 10% and condensates as high as 15.5%. These cases are
rare, however, and usually have very high tank liquid
gravities.
Near-critical gas-condensate reservoir. If the reservoir
temperature is near the critical temperature, as shown in Figure
4.2c, the hydrocarbon mixture is classified as a near-critical gas-
condensate. The volumetric behavior of this category of natural
gas is described through the isothermal pressure declines as
shown by the vertical line 1-3 in Figure 4.2c. Because all the
quality lines converge at the critical point, a rapid liquid buildup
will immediately occur below the dew point as the pressure is
reduced to point 2

This behavior can be justified by the fact that several quality

lines are crossed very rapidly by the isothermal reduction in
pressure. At the point where the liquid ceases to build up and
begins to shrink again, the reservoir goes from the retrograde
region to a normal vaporization region.
Figure :4.2c A typical phase diagram for a near-
critical gas condensate reservoir.
Wet-gas reservoir: A typical phase diagram of a wet gas is
shown in Figure 4.2d, where reservoir temperature is above
the cricondentherm of the hydrocarbon mixture. Because
the reservoir temperature exceeds the cricondentherm of the
hydrocarbon system, the reservoir fluid will always remain
in the vapor phase region as the reservoir is depleted
isothermally, along the vertical line A-B. As the produced
gas flows to the surface, however, the pressure and
temperature of the gas will decline. If the gas enters the two-
phase region, a liquid phase will condense out of the gas and
be produced from the surface separators.
This is caused by a sufficient decrease in the kinetic energy
of heavy molecules with temperature drop and their
subsequent change to liquid through the attractive forces
between molecules. Wet-gas reservoirs are characterized by
the following properties:

• Gas oil ratios between 60,000 to 100,000 scf/STB*

• Stock-tank oil gravity above 60° API
• Liquid is water-white in color
• Separator conditions, i.e., separator pressure and
temperature, lie within the two-phase region.

* standard cubic foot per stock tank barrel.

Figure :4.2d Phase diagram for a wet gas.
Dry-gas reservoir: The hydrocarbon mixture exists as a
gas both in the reservoir and in the surface facilities. The
only liquid associated with the gas from a dry-gas
reservoir is water. A phase diagram of a dry-gas reservoir
is given in Figure 4.2e. Usually a system having a gas-oil
ratio greater than 100,000 scf/STB is considered to be a
dry gas. Kinetic energy of the mixture is so high and
attraction between molecules so small that none of them
coalesce to a liquid at stock-tank conditions of
temperature and pressure. It should be pointed out that
the classification of hydrocarbon fluids might be also
characterized by the initial composition of the system.
* standard cubic foot per stock tank barrel.
Figure :4.2e Phase diagram for a dry gas..
From the foregoing discussion, it can be observed that
hydrocarbon mixtures may exist in either the gaseous or
liquid state, depending on the reservoir and operating
conditions to which they are subjected. The qualitative
concepts presented may be of aid in developing
quantitative analyses. Empirical equations of state are
commonly used as a quantitative tool in describing and
classifying the hydrocarbon system
Wells in the same reservoir can fall into categories of oil,
condensate, and gas wells depending on the producing gas–
oil ratio (GOR).Gas wells are wells with producing GOR
being greater than 100,000 scf/stb; condensate wells are
those with producing GOR being less than 100,000 scf/stb
but greater than 5,000 scf/stb; and wells with producing
GOR being less than 5,000 scf/stb are classified as oil wells.
Well
Oil and gas wells are drilled like an upside-down
telescope. The large-diameter borehole section is at
the top of the well. Each section is cased to the
surface, or a liner is placed in the well that laps
over the last casing in the well. Each casing or liner
is cemented into the well
The ‘‘well head’’ is defined as the surface equipment set
below the master valve. As we can see in Fig. 4.3, it
includes casing heads and a tubing head. The casing head
(lowermost) is threaded onto the surface casing. This can
also be a flanged or studded connection. A ‘‘casing head’’
is a mechanical assembly used for hanging a casing string
(Fig. 4.4). Depending on casing programs in well drilling,
several casing heads can be installed during well
construction.
Figure 4.3 A sketch of a wellhead.
Figure 4.4 A sketch of a casing head.
Most flowing wells are produced through a string of
tubing run inside the production casing string. At the
surface, the tubing is supported by the tubing head (i.e.,
the tubing head is used for hanging tubing string on the
production casing head [Fig. 4.5]).

Figure 4.5 A sketch of a tubing head.

The equipment at the top of the producing wellhead is
called a ‘‘Christmas tree’’ (Fig. 4.6) and it is used to
control flow. The ‘‘Christmas tree’’ is installed above
the tubing head. An ‘‘adaptor’’ is a piece of equipment
used to join the two. The ‘‘Christmas tree’’ may have
one flow outlet (a tee) or two flow outlets (a cross).
Figure 4.6 A sketch of a ‘‘Christmas tree.’’
A Christmas tree consists of a main valve, wing valves,
and a needle valve. These valves are used for closing the
well when needed. At the top of the tee structure (on the
top of the ‘‘Christmas tree’’), there is a pressure gauge
that indicates the pressure in the tubing. The wing valves
and their gauges allow access (for pressure measurements
and gas or liquid flow) to the annulus spaces (Fig. 4.7).
Figure 4.7 A sketch of a surface valve.
‘‘Surface choke’’ (i.e., a restriction in the flowline) is a piece
of equipment used to control the flow rate (Fig. 4.8). In
most flowing wells, the oil production rate is altered by
adjusting the choke size. The choke causes back-pressure in
the line. The back-pressure (caused by the chokes or other
restrictions in the flowline) increases the bottomhole
flowing pressure. Increasing the bottom-hole flowing
pressure decreases the pressure drop from the reservoir to
the wellbore (pressure drawdown). Thus, increasing the
back-pressure in the well-bore decreases the flow rate from
the reservoir
Figure 4.8 A sketch of a wellhead choke.
Surface vessels should be open and clear before the well is
allowed to flow. All valves that are in the master valve and
other downstream valves are closed. Then follow the
following procedure to open a well:

1. The operator barely opens the master valve (just a

crack), and escaping fluid makes a hissing sound. When
the fluid no longer hisses through the valve, the pressure
has been equalized, and then the master valve is opened
wide.

2. If there are no gas/oil leaks, the operator cracks the next

downstream valve that is closed. Usually, this will be
either the second (backup) master valve or a wing valve.
Again, when the hissing sound stops, the valve is opened
wide.
3. The operator opens the other downstream valves the
same way.

4. To read the tubing pressure gauge, the operator must

open the needle valve at the top of the Christmas tree.
After reading and recording the pressure, the operator
may close the valve again to protect the gauge.

The procedure for ‘‘shutting-in’’ a well is the opposite of the

procedure for opening a well.
 Flow Regimes

When a vertical well is open to produce gas/oil at production

rate q, it creates a pressure funnel of radius r around the
wellbore, as illustrated by the dotted line in Fig. 4.9a. In this
reservoir model, the h is the reservoir thickness, k is the
effective horizontal reservoir permeability to gas, μg is
viscosity of oil, Bg is gas formation volume factor, rw is
wellbore radius, pwf is the flowing bottom hole pressure, and p
is the pressure in the reservoir at the distance r from the
wellbore center line. The flow stream lines in the cylindrical
region form a horizontal radial flow pattern as depicted in
Fig. 4.9b.
Figure 4.9 A sketch of a radial flow reservoir model: (a)
lateral view, (b) top view.
 Transient Flow

‘‘Transient flow’’ is defined as a flow regime where/when

the radius of pressure wave propagation from wellbore has
not reached any boundaries of the reservoir. During
transient flow, the developing pressure funnel is small
relative to the reservoir size. Therefore, the reservoir acts
like an infinitively large reservoir from transient pressure
analysis point of view.
 Steady-State Flow

‘‘Steady-state flow’’ is defined as a flow regime where the

pressure at any point in the reservoir remains constant over
time. This flow condition prevails when the pressure funnel
shown in Fig. 4.9 has propagated to a constant pressure
boundary. The constant-pressure boundary can be an
aquifer or a water injection well. A sketch of the reservoir
model is shown in Fig. 4.10, where pe represents the pressure
at the constant-pressure boundary.
Figure 4.10 A sketch of a reservoir with a constant-pressure
boundary.
 Pseudo–Steady-State Flow

‘‘Pseudo–steady-state’’ flow is defined as a flow regime where

the pressure at any point in the reservoir declines at the same
constant rate over time. This flow condition prevails after the
pressure funnel shown in Fig. 4.9 has propagated to all no-
flow boundaries. A no-flow boundary can be a sealing fault,
pinch-out of pay zone, or boundaries of drainage areas of
production wells. A sketch of the reservoir model is shown in
Fig. 4.11, where pe represents the pressure at the no-flow
boundary at time t4.
Figure 4.11 A sketch of a reservoir with no-flow boundaries.
Thank You