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Gas expansionIs gas the fuel of the future? Is it the answer to all of our environmentalproblems? Can gas prevent the energy crisis which the world faces as oilsupplies dwindle in the next century? Recently, there have been some very grand claims made for the role of gas infuture world energy budgets, and the gas sector is undergoing rapidexpansion. Can it live up to these forecasts?In this article, Sylvie Cornot-Gandolphe of CediGaz, Dr. Abdul Fattah A.R. Abedand Ibrahim Marzouk of ADNOC, Roy Nurmi, and Andrew Hayman ofSchlumberger examine current trends in gas technology, global productionand consumption, and discuss the long-term prospects for gas.
Contributors: David Teggin, Jean-Louis Chardac, Antoine Lopez, and Phillipe Maguet.
Special thanks to Maureen Jones, Schlumberger-Doll Research Librarian for her help in locating materialused in this and other Middle East Well Evaluation Review articles.
Middle East Well Evaluation Review32
Within the world-wide petroleum
industry the gas sector is grow-
ing fast. Proven gas reserves
have more than trebled over the last 20
years and are increasing almost one
and a half times faster than gas is being
consumed. New oil reserves, by com-
parison, have barely matched global
consumption between 1975 and 1988.
Geographically, gas discoveries since
the 1970s have occurred mainly in the
new gas-producing countries. Relatively
little has been found by the major gas
consumers, except in the former Soviet
Union. Consequently, the industrialized
countries in the West now control only
11% of world reserves, while they con-
sume about 50% of current world pro-
duction (figure 2.1). However, a further
inspection of this figure reveals another
serious imbalance between reserves
and probable demands: the former
Soviet Union and the Middle East con-
trol almost 70% of global gas reserves
between them.
Demand for natural gas will certainly
rise over the next 25 years (figure 2.2),
with most of the increase coming from
Eastern Europe, the Commonwealth of
Independent States (CIS) and the Less
Developed Countries (LDCs) of Asia
and Africa. Gas consumption will grow
moderately in Western Europe, Japan,
Australasia and in the North American
market.
In the past, gas exploration has been
a very low priority for the oil industry.
During oil production, vast quantities of
gas have been flared, simply because
collection and distribution costs have
been higher than anticipated revenues.
So what has sparked our most recent
interest in gas? Strong economic growth
between 1985 and 1990 set new levels in
total energy consumption, with gas
emerging as the main beneficiary. In
just five years demand rose by 18%. Gas
is efficient, particularly for electrical
generation. In combined-cycle plants
and electricity/heat cogeneration sys-
tems, gas also offers cheap investment
and operating costs. It is this industrial
sector which lies at the heart of all pre-
dictions about greater gas demand. In
addition, environmental awareness has
greatly influenced the economic equa-
tions, to the extent that gas is increas-
ingly favoured as a replacement for oil
and coal.
At the end of the 1980s several Mid-
dle East countries were flaring more
than 10 billion m3 of gas each year. This
represented half of one percent of
world production, and the energy being
wasted was equivalent to almost 20 % of
Japan's annual gas consumption. Gas
flaring is a waste of natural resources
and damages the environment without
bringing any energy-producing benefits.
Several countries have taken steps to
control, reduce or eradicate flaring. In
1984 Saudi Arabia introduced the Master
Gas System, which has reduced flaring
dramatically. While in India, the deci-
sion has recently been taken to aim for
zero flaring.
At present there are several eco-
nomic obstacles facing each new gas
development. Investment in plant for
natural gas processing and the high
transport costs, particularly for Liquified
Natural Gas (LNG), are proving prohibi-
tive for all but the biggest fields.
In future, new reservoirs entering
production will probably be located in
frontier environments, far from estab-
lished markets. This will increase pro-
duction costs, transport costs and gas
prices in the international market. In the
long term, increasing distances between
production and consumption will favour
the use of LNG tankers over gas
pipelines (figure 2.3). Moreover, the
pipeline option demands a considerable
initial investment, which some see as
increasing financial risk, whereas the
LNG chain is modular.
3500
3000
2500
2000
1500
1000
0
500
1990
2000
2020
bcm
2030
2500
3400
LDCs
Eastern Europe & CIS
Japan
Australia
New Zealand
Western Europe
North America
World gas demand outlook 1990-2020
Reserves Demand
1970
1993
1992
32,400 146,000 2108Billion m3
Share of OECD countries 34% 11% 47%
Asia/Oceania
Eastern Europe & CIS
AfricaMiddle East
Latin America
Western EuropeNorth America
The world imbalance between gas reserves and demand
Fig. 2.2: REASONABLE DEMANDS? As the gas
market develops increased consumption will
be concentrated in Eastern Europe, the
former Soviet Union and in the Less
Developed Countries of Asia and Africa. Gas
consumption will grow moderately in
Western Europe, Japan, Australasia and in
the North American market.
Fig. 2.1: YOU WANT
IT, WE'VE GOT IT:
The countries of the
Middle East and
those which
comprised the
former Soviet Union
control almost 70 %
of global gas
reserves. The
industrialized
countries of the
west control only
11% of reserves, but
consume almost
half of present
production.
Sylvie Cornot-Gandolphe (1992) The Future of International
Gas Projects and Financial Implications. Presented at the 6th
Annual APS Conference, Nicosia, Cyprus, 1992.
M. Valais and S. Cornot Gandolphe (1993) The World LNG
Trade Perspective: Potential and Realities. Paris, France,
February 1993.
Number 15, 1994. 33
845 776
C.I.S. - Eastern Europe
109 107
Middle East
219 319
Western Europe
76 42
Africa
162 166
Asia-Oceania109 107
Latin America 3.5
7
9.6
3.9
3.5
5.2
1.3
29.7
1.9
5.7
4
1.32.5
1.6
38.6
24.7 63.3
39.9
14.8
47.4
2.2
1.7
World natural gas In 1992 - billion cubic metresMarketed production 1992 - World total 2,120 billion m3 Consumption 1992 - World total 2,120 billion m3
Trade by pipeline: 245 billion m3 Trade by LNG tanker: 77 billion m3
109 107
North America
Production Consumption
Fig. 2.4: International trade in gas has developed three distinct markets: the Americas, Europe and the Far East. Competition,
supply and costs are different in each region.
Trading partners
The world gas map (figure 2.4) indicates
the trading patterns which are being
established in regional markets around
the world. The three main markets are
North America (with Canada established
as a major supplier), Europe and South
East Asia, where Japan’s buoyant econ-
omy has emerged as the major market
for natural gas. In contrast to the oil mar-
ket, there is no global price for gas. The
three regional markets are characterized
by three different price structures. Low
prices in North America reflect a situa-
tion where suppliers face high levels of
competition. In Europe, where there are
fewer supply options, gas is marginally
more expensive. In the Far East, gas is
only supplied as LNG, an expensive
option which passes high transport
costs on to consumers.
On January 1, 1993, proven gas
reserves amounted to 146,000 billion m3.
That is equivalent to 97 % of proven oil
reserves. In the near future gas reserves
will exceed oil reserves, because of the
increased emphasis on gas exploration,
and the fact that the majority of oil
provinces have been explored.
43
236
3
72
300
120
450
250
1970 1990 2000 2020
400
300
200
100
0
500
Pipelines
LNG
World gas trade outlookLNG vs. pipeline trade 1970-2020
Fig. 2.3: SHIPS AND PIPES: Gas can be distributed along pipelines or liquified and loaded into
tankers to be shipped around the world. Pipelines were favoured by the countries which
established themselves as major exporters in the 1970s. However, the Liquified Natural Gas (LNG)
option (shipped by tanker) is gaining ground as the distance between reserves and markets grows.
Middle East Well Evaluation Review34
Gas reserves have been closing the
gap on oil since 1970 (figure 2.5) when
they amounted to approximately half of
the equivalent oil reserves. One estimate
of ultimate natural gas resources sug-
gests a figure between 400,000 billion m3
and 500,000 billion m3. Since proven
reserves amount to less than 150,000 bil-
lion m3, this indicates the ample oppor-
tunities for discovering new giant or
supergiant fields around the globe.
Breaking down the geographical loca-
tion of proven gas reserves in more
detail (figure 2.6) we see that the Middle
East, where reserves are still growing,
contains more than a quarter of the
total. Russia and the other members of
0
20
40
60
240
220
200
180
160
140
120
100
80
1990 2000 2020
5.4
31.4 61 85
152
31
North Africa Middle East
billi
on c
ubic
met
res
Evolution of natural gas trade in the Middle East and North Africa
Breakdown of proven natural gas reserves 1.1.1993
65.5% Others
46.2% Iran
12.9% UAE11.7% Saudi Arabia
5.8% Qatar
13.4% Others
30.7% Middle East44,809 billion m3
3.8% North Africa5,480 billion m3
World 145,918 billion m3
95,629 billion m3
150
100
50
0
1970 1975 1980 1985 1990
Gas
to o
il eq
uiva
lent
World proven reserves of oil and natural gas
Natural gas
oil
50%
80%
86%
Gas/oil ratio of
proven reserves
97%
Fig. 2.5: THE GROWTH OF GAS: Proven gas reserves have grown dramatically over
the last 20 years. In the near future natural gas reserves will exceed total oil reserves.
Many of the new gas accumulations will be found in the Middle East.
Fig. 2.6: The
Middle East
contains more
than a quarter of
the world’s total
gas reserves. Gas
consumption in
this region is
expected to
double over the
next 30 years.
Values given in
billion m3(bcm).
Fig. 2.7: The increases predicted for
gas consumption in North Africa
and the Middle East will be driven
by rising energy demands in those
regions. Increased gas consumption
(resulting from the use of gas rather
than oil for domestic energy
production) will help to maintain
oil export levels.
Who needs gas?
Japan introduced LNG in 1969 and by 1977
more than half of the world’s LNG ship-
ments were bound for Japanese ports.
Korea and Taiwan, which started import-
ing LNG in 1986 and 1990 respectively, are
experiencing rapid growth in demand for
power generation and distribution. In 1992
Japan, Korea and Taiwan imported more
than 44 million tonnes of LNG, nearly
three-quarters of the global trade.
More than 90 % of the demand in
these three countries is met by Pacific
Rim countries: Indonesia, the world’s
largest exporter of LNG, Malaysia,
Brunei, Australia and Alaska, with Abu
Dhabi contributing to the balance.
Reserves
Large reserves are a basic requirement
for any LNG scheme and the Middle
East, with reserves in excess of
40,000 billion m3 is matched only by the
Commonwealth of Independent States
(CIS). Furthermore, Middle East reserves
represent 270 years of production at
1992 levels, while those in the CIS will be
exhausted in 70 years if production con-
tinues at the 1992 rate.
the CIS hold an important share, while
the countries of North Africa, which sup-
ply large quantities of gas to the Euro-
pean market, account for about 4% of
global reserves. Most of the North African
reserves are concentrated in Algeria.
Gas consumption in the Middle East
is expected to double by the year 2020,
while in North Africa the rise in con-
sumption will be even more spectacular
(figure 2.7). This expansion of domestic
gas markets in producing countries will
serve two purposes; first to meet the
energy demands of population growth,
and second, to maintain levels of oil
export by using gas, rather than oil, for
domestic energy production.
Number 15, 1994 35
Fig. 2.8: NEXT TRAIN FOR ABU DHABI:
The third Liquified Natural Gas (LNG)
processing train at Das Island, Abu
Dhabi is scheduled to open early in
1994.
Certified gas reserves available from
the North Field in Qatar could justify 35
liquefaction units, each delivering 2 mil-
lion tonnes of LNG each year for the
next 50 years. The North Field could
supply the Japanese market, at current
levels, for 100 years.
In the next century, as more of the
gas produced in Pacific Rim countries is
dedicated to growing local demand, LNG
from the Middle East will fill the energy
gap. Huge reserves are important when
negotiating and renewing supply con-
tracts, providing a strong guarantee of
long-term security and availability.
Middle East LNG has a 15-year his-
tory and existing delivery agreements
were honoured throughout the recent
Gulf War.
Costs in the LNG chain
How does the cost of supplying LNG
from the Middle East compare to other
suppliers in the global market? There
are three basic cost components associ-
ated with the sale of LNG:
• Upstream - production facilities and
gas gathering systems.
• Liquefaction and storage of liquid.
• Shipping.
While the actual figures for any devel-
opment are variable, liquefaction and
storage generally account for a large pro-
portion of these costs.
Upstream costs in the Middle East are
generally lower than in other parts of
the world. Fields are large and can be
developed relatively easily.
Liquefaction costs are comparable to
those elsewhere in the world, although
they may be marginally higher if the gas
is to be produced from remote areas.
The large reserves help to offset this by
offering economies of scale and sharing
of infrastructure. Nevertheless, any large
scale development of Middle East LNG
production would lead to a rapid
decrease in average liquefaction costs.
Shipping costs, however, are nearly
twice as high as those of competing pro-
jects which are located halfway to the
consumer. In the early stages of devel-
opment, LNG from the Middle East will
only be competitive if operators concen-
trate on fields which are large and easy
to develop, thereby balancing the nega-
tive effects of geographical isolation.
Additional economic benefits of Mid-
dle East gas production will be derived
from the condensates normally associ-
ated with gas production in this region.
These valuable by-products will gener-
ate supplementary revenues, and so
improve the economic equation.
And in the future...
Abu Dhabi’s LNG capacity will receive a
boost early in 1994 with the opening of
the third liquefaction train at Das Island
(figure 2.8). In 1997, Qatar will join Abu
Dhabi as a supplier to the Far East mar-
ket. Beyond the year 2000, Middle East
LNG should become increasingly impor-
tant as Far East consumers recognize the
importance of a clean energy source.
There is still a possibility that the
Middle East’s reserves will find a major
outlet in the gas-hungry European mar-
kets, where prices will almost certainly
increase as gas demand outstrips the
supply from the CIS and Algeria. If this
were to happen, the Middle East’s cur-
rent geographical isolation from the
major world markets in the Far East
would be transformed into a prime posi-
tion. It would be located halfway
between two major markets whose fluc-
tuating seasonal requirements appear
complementary.
In future LNG will face opposition
from two main sources: nuclear power,
still identified by many as the major
long - term solution to energy supply,
and coal which, in the long term, may
become economically and environmen-
tally attractive as a result of technologi-
cal advances.
However, the Middle East faces a
bright but challenging future as the LNG
market evolves.
Qatar
Saudi Arabia
Oman
DasIsland
AbuDhabi
U n i t e d A r ab
Emi r
at e
s
Middle East Well Evaluation Review36
Khuff gas
Proposed pipeline route
••••
••
•
•••
••
• New gas discoveries
Main gas-producing areas
Cretaceous, Mioceneassociated gas
Red Sea Highgas potential
Cretaceous, Mioceneassociated gas
Indus Basin
Jurassicassociated gas
Bassein field
Lower Palaeozoicsandstone
0 400 800km
Asian plate
African plate
Arabian plate
Indian plate
Gulf of Aden
Gulf of Oman
Jurassic,Cretaceousassociated gas Cretaceous
high pressure gas
Tapiti gas sands
Bombay High
Western Desert
Nile Delta
Syria
Central Oman Arch
New Khuff
Khuff and Pre-Khuff gas areas
countries such as Qatar, Oman, Yemen
and Iran are developing gas export
strategies, following the pattern set by
Abu Dhabi which supplies significant
quantities of LNG to Japan.
Whether the gas market can absorb
the proposed increases in LNG capacity
remains unclear. However, reduced
transport and storage costs are the key
elements in successful LNG pro-
grammes, particularly in view of low oil
prices and possible competition from
proposed transnational gas pipelines.
The Middle East gas ring
Iran, India and Japan are discussing pro-
posals for a major project which will
involve constructing a set of pipelines to
distribute natural gas from the Middle
East (figure 2.9).
The gas distribution project is a
strand of the Middle East peace process.
It is hoped that this international gas
project will help to bring stability to the
region, offer significant environmental
benefits and improve the security of
global energy supply.
The main feature of the proposal is a
6000 km pipeline ‘loop’ within Saudi Ara-
bia comprised of three main sections.
• A central pipeline (48 inch diameter)
which would supply gas to Middle East
countries.
• An eastern pipeline stretching from
Iran to Kandla on the west coast of
A world of gas
There are more than 26,000 gas fields
around the world, nearly 20,000 of which
are located in North America. However,
a closer look at the figures reveals that of
the world total, only 24 fields are super-
giants - that is fields containing at least
1000 billion m3 of natural gas. Taken
together, these enormous fields account
for approximately 36 % of world
reserves. Eleven supergiants are located
in the territories of the former USSR and
nine in the Middle East.
Approximately half of the world's gas
reserves consists of dry and clean gas.
For these gases processing is extremely
simple (dehydration/compression). A
further 20 % is wet, clean gas from which
liquid hydrocarbons must be removed
before the gas can be shipped. The
remaining 30 % consists of acid gas,
which may be either dry or wet but, as it
contains corrosive compounds, requires
complex processing procedures. Acid
gas may be considered too costly, and
production from this type of field could
be delayed - especially in small, inacces-
sible fields.
Moving it around
New LNG exporters are emerging across
the globe. Recent discoveries in Egypt
are expected to stimulate the gas export
market. Elsewhere in the Middle East,
Fig. 2.9: Gas distribution in and around
the Middle East, including new major gas
discoveries. The proposed Middle East
gas pipeline would tap some of the
world’s largest fields of liquid-rich
natural gas, with combined reserves
exceeding 42 trillion m3.
India. This would supply gas for a major
LNG export system designed to cater for
the Asian/Pacific markets.
• A western pipeline running between
Amman and Morocco which would feed
the EC gas supply network.
The loop could pump more than
20 million tonnes/year to the Indian ter-
minal in the east, and a similar quantity
through the western Morocco-bound
pipeline.
This ambitious project would tap
some of the world’s largest fields of liq-
uid-rich natural gas, with recoverable
reserves exceeding 42 trillion m3. The
gas fields of Iran, the North Dome struc-
ture of Qatar/Iran, and a string of fields
from the Nile Delta to Algeria would
feed the pipeline. Extensions to the loop
could supply virtually all of the coun-
tries of the Middle East and North Africa
at relatively low cost.
While this major project remains in
the discussion and early planning
stages, countries in and around the Mid-
dle East are eager to develop the inter-
national pipeline network. Oman and
India have recently agreed to cooperate
on a major gas pipeline project.
Number 15, 1994 37
The AVO difference
AVO can identify fluid content by com-
paring real data with a standard - the
synthetic seismogram. This ‘synthetic’ is
an artificial seismic trace generated by
assuming that a pulse travels through an
earth model - rock layers of variable
thickness, density and seismic velocity.
The model can be altered repeatedly
until the synthetic matches the real data,
indicating that the model is a close
approximation to the actual structure at
depth. The densities and velocities of
fluid saturated rocks to be incorporated
into the synthetic should preferably
come from core or log data. Missing data
can be estimated using theoretical or
empirical equations.
Prestack amplitude analysis
A recent study compared the AVO char-
acteristics of three distinct bright spots
seen on seismic sections from the Po
Valley, Italy. Two of these were caused
by gas sands, but the third was due to
water in a gravel layer.
The amplitude analysis included
reflections from the entire range of inci-
dence angles available in the survey.
Analysis was extended to longer offsets in
the hope that possible critical-angle phe-
nomena might be revealed. The energy
trend of synthetic reflections for the
water-filled gravel layer showed an initial
decrease, but increased sharply at larger
offset distances (figure 2.10a). Plots for the
gas-bearing sands (figure 2.10b and 2.10c)
presented a very different trend, indicat-
ing the sensitivity of the measurement to
distinguish gas from water.
Searching with seismics
If the approximate size and shape of a
hydrocarbon reservoir could be identi-
fied with a high degree of certainty
before drilling, the method used would
completely revolutionize oil and gas
exploration. The Amplitude Versus Off-
set (AVO) technique helps us towards
that goal by providing a means to iden-
tify gas-oil and oil-water contacts with
great precision over large areas.
Early indications that fluids could be
seen on seismic sections came from
high amplitude streaks in sequences
which came to be known as ‘bright
spots’. First recognized in the 1970s,
many of these bright spots were identi-
fied as gas caps in sedimentary
sequences. However, as drillers quickly
discovered, bright spots can also be gen-
erated by various rock types and for a
variety of different reasons.
When seismic sections are processed
conventionally, any tight or hard rocks
in the sequence can produce similar
high amplitude spots to those character-
istic of hydrocarbons. AVO can help dis-
tinguish hydrocarbon bright spots from
those caused by other geological varia-
tions: this has offered fresh hope that
seismic could lead the way in defining
precise sizes and shapes of hydrocar-
bon reservoirs.
0.00 0.00
Actual DataSynthetic Data
Actual DataSynthetic Data
Actual DataSynthetic Data
3.00
2.00
1.00
0.00
2.00
1.00
2.00
1.00Env
elop
e E
nerg
y
Env
elop
e E
nerg
y
Env
elop
e E
nerg
y
25 475 975 1475 1975 2375Offset (m) 25 475 1475 1975 2375Offset (m) 25 475 975 475 1975 2475Offset (m)
Ray Incident 1° 30° 60°Angle
Ray Incident 1° 30° 60°Angle
Ray Incident 1° 25° 50°Angle
Fig. 2.10: SAND, GRAVEL, GAS AND WATER: The graphs show the different energy trends for synthetic reflections for a water-bearing gravel layer (a)
and two gas-bearing sand layers (b and c). Although all three appear as ‘bright spots’ on conventional seismic sections, pre-stack amplitude analysis
allows geophysicists to distinguish gas from water. (After Alfredo Mazzotti of AGIP, 1990).
The future for AVO
Some companies use AVO on a routine
basis to assess the quality of potential
drilling locations. Others, having tried
the technique, consider the processing
too time-consuming or too difficult. An
increasing number are demanding
quantitative agreement between syn-
thetic and observed data before they
will use the technique. At present, most
AVO examples show excellent qualita-
tive results but leave room for improve-
ment in quantitative matching. In the
study area qualitative analysis of syn-
thetic and real data from AVO can be
used to distinguish dry bright spots,
associated with high velocity layers,
from gas-related bright spots. Current
research efforts are focused on eliminat-
ing the discrepancy between observed
and synthetic data.
Accurate values of compressional
and shear velocity and density are
required to generate synthetics for cali-
bration. The DSI tool can measure
velocity (including shear velocity) in
slow formations which would be
beyond the range of other tools.
Edward Chiburis et al. (1993): Hydrocarbon Detection With
AVO. Oilfield Review, January 1993, pp 42-50.
Alfredo Mazzotti (1990): Prestack amplitude analysis method-
ology and application to seismic bright spots in the Po Valley,
Italy. Geophysics 55, pp 157-166.
(a) (b) (c)
Middle East Well Evaluation Review38
1400
1300
1200
1100
1000
30
29
28
4.2
4.0
3.8
3.6
Flo
w in
/out
(l/m
in)
Act
ive
tank
vol
ume
(m3 )
Sta
ndpi
pe p
ress
ure
(MP
a)
Flow out
Flow in
Delta - flowalarm
Pit gainalarm
0 100 200 300 400 500Time (seconds)
Pressure dropalarm
The kick box A ‘kick’ is the sudden influx of oil, gas or
water into the borehole from a pressured
rock formation. Early detection of a kick
is a vital part of the safety procedures on
a drilling rig. All drilling operations must
have a kill plan: the procedure which
counteracts dangerous pressure buildup.
Killing a well normally involves either
pumping dense muds into the well or
drilling a separate, intersecting well to
reduce pressure. Failure to implement a
kill plan can be catastrophic - at worst
causing a blow-out. Kicks are particularly
common in gas wells where the forma-
tions being drilled are deep and typically
contain high-pressure fluids.
The first indication of many kicks is a
change in the flow-in, flow-out figures of
the well being drilled (figure 2.11). Accu-
rate flow measurement is, therefore,
essential.
It is critical for the safe operation of a
drilling rig that the driller has full access
to all the information relating to activities
on the rig. A computerized system can
help by providing early warning of
potentially disastrous events, detecting
them before they become critical, and
alerting the driller to the danger.
Kick detection computers can be inte-
grated into existing systems with the min-
imum of disruption. Offshore, the marine
riser can be adapted to allow accurate
measurement of, and compensation for,
rig heave while making flow measure-
ments. During drilling and circulating
operations the real-time computer sys-
tem constantly monitors active system
volume and differential flow: flow-out
minus flow-in. These two measurements
are complimentary, with differential flow
giving a clear indication of rapid influxes,
while the pit levels (measured in the
chambers on the rig which contain the
drilling muds) are suitable for identifying
slow influxes.
In order to deal with the problem the
driller needs to have some idea of the
kick volume - the amount of fluid which
has entered the well. Existing kick detec-
tion algorithms have been extended to
estimate influx volume at the time the
Blow-Out Preventer (BOP) is closed.
An example (figure 2.12) shows the
operation of Anadrill's computerized
well control system in a full-scale test
well. Arrows on the figure indicate
where the ‘smart’ alarms operated by
identifying statistically significant trends
in the data. The D-flow information gave
the earliest indication of the kick, in this
case at less than 2bbls pit gain. This was
followed by triggering of the active tank
influx alarm while total pit gain was less
than 5bbls (0.8m3). Normally the pumps
would have been shut-down at this stage
for a flow-check. However, the aim was
to produce a known volume of influx, so
Fig. 2.12: KICK
START: Three
separate alarm
systems can be
integrated into
the computerized
kick monitoring
system. In this
case the
computerized
system was
allowed to run
past the second
alarm. This
would normally
have shut down
the pumps while
a flow check was
conducted.
Standpipepressure
transducer
Annuluspressure
transducer
Gas-cutmud
Mud pump
Signalprocessing
module
Sonictraveltime
Period‘n’
Phaseshift‘∅’
Fig: 2.11: INS AND OUTS OF KICK DETECTION: The difference between fluid flow into and
out of the well, differential flow, is the earliest indication of a sudden hydrocarbon influx or
‘kick’ (a). Failure to identify a kick quickly can compromise rig safety (b).
(a)
(b)
Number 15, 1994. 39
gas injection continued until the total
injected volume reached 7.5bbls (1.2m3).
A third alarm was then activated, warning
of a drop in standpipe pressure caused
by loss of hydrostatic head in the annu-
lus. The combination of alarms con-
firmed, in real time, the presence of an
influx. Research into early-warning sys-
tems continues, and the first indications
of gas influxes can be obtained from ultra-
sonic sensors built into Measuring While
Drilling (MWD) equipment.
However, once a kick has been
detected and the well shut-in, the prob-
lem of circulating out the influx remains.
This stage has also been computerized,
with its own monitoring system.
After shut-in, a lot of information about
the well can be found from analysis of sur-
face pressure measurements. The pres-
sure build up can be used in much the
same way as a drill stem test (DST).
Important parameters such as casing and
drill pipe pressure can be determined
automatically, passed to the driller and
used to generate a kill plan for the well.
In at the kill
As soon as the detected shut-in data has
been verified a kill plan is generated automat-
ically. Pressure measurements are displayed
in real-time for comparison with the pressure
profile required for choke operation. Pre-
dicted shoe pressure is calculated every sec-
ond using a model with input parameters
from the shut-in analysis. The system then
performs a number of additional calcula-
tions:
• Well geometry is computed to obtain a
pressure profile which is sufficiently accu-
rate for horizontal and highly-deviated wells.
• Kill mud weight (the well is controlled
by pumping high density muds) and pres-
sure values are calculated.
Collapsed wellbore
Normal pressure
Undercutting
Normalpressure
Collapsedwellbore
Depleted pressure
Fig. 2.13: Wellbore bridging is the
process which ends most gas
blowouts. The shaly formation
overlying the high-pressure gas
sand collapses as a result of
pressure differences (a and b) or
because of undercutting by the gas
as it moves up the well (c and d).
When formation bridging does not
occur the blowout may continue
for months, with gas burning on
the sea (e).
Fig. 2.14: Gas released from shallow blowouts
changes the density of the water column.
Fortunately, the volumes of gas involved are
not normally enough to alter water density
significantly. A major density reduction could
sink ships or semi-submersibles.
(a) (b)
(c) (d)
• A kill pressure profile is generated.
Once generated, the kill plan is dis-
played on the same log track as the mea-
sured standpipe pressure. A real-time
model, which estimates annular pres-
sure during the kill procedure, can then
be generated. These models have been
validated using measurements from a
test well fitted with downhole transduc-
ers.
Shallow gas blowouts
Shallow gas blowouts have been
responsible for the loss of more off-
shore drilling rigs than any other type of
well control problem. They are, accord-
ing to the firefighters, the most difficult
to kill.
Once a shallow gas blowout occurs
there is very little chance to control it
with equipment available on the drilling
rig. Formation bridging (figure 2.13a-d)
stops many shallow blowouts, but those
it fails to control must be stopped by
direct vertical intervention or drilling of
a relief well.
Occasionally a well which is not
stopped by formation bridging will blow
for months or even years before pres-
sure depletion ends the flow. In some of
these wells, gas flow outside the casing
can cause huge explosions and open
deep craters in the sea bed.
Fire on the water
In some blowouts the plume of gas ris-ing from the well will ignite when itreaches the surface of the sea (figure2.13e). This is not a problem if the vol-ume of gas is small, or if it reaches thesurface some distance from the rig.However, a burning gas plume immedi-ately below the drilling rig would ruleout the possibility of a vertical kill.
(e) That sinking feeling
Gas plumes rising through seawater tend
to reduce the density of the water
through which they are moving (figure
2.14). In most cases the volumes of gas
released will only cause minor density
changes.
However, recent work carried out by
scientists at the US Geological Survey
suggests that large-scale releases of nat-
ural gas from continental shelf margins
might represent a serious threat to ships.
Huge volumes of gas are believed to
accumulate in unconsolidated sediment
on the edges of the North American con-
tinental shelf. The gas is overlain by a
condensate layer which holds it in the
sediment. Landslides which can be trig-
gered by small earth tremors, cause the
slopes to fail, removing the condensate
layer and releasing the gas.
Ships stay afloat because their overall
density (metal and air contained inside
the metal hull) is less than that of the
water which they displace. If the water
under the hull of a ship was saturated
with, or completely displaced by, a huge
bubble of natural gas, the ship would
sink. Sediment redistribution following
the landslide would tend to hide the
remains of the ship. This theory has
recently been proposed by some scien-
tists to account for some unexplained
ship disappearances.
Nea
l Ada
ms
Fire
fight
ers
N. Adams and L. Kuhlman (1991) Shallow Gas Blowout Kill
Operations. SPE Paper 21455. Presented at the Middle East
Oil Show, Bahrain, November 1991.
Qatar
Saudi Arabia
Oman
Dubai
Shah
Asab
SahilBu Hasa
Bab
UmmAl
DakhUmm
AlAnbar
Mubarras
Umm ShaifSatah
Arzana
El Bunduq
Zakum
Nasr
Gas
Oil
DasIsland
Abu Al Bukoosh
Middle East Well Evaluation Review40
Getting gas from theground
Gas wells are generally deeper and,
therefore, more expensive to drill than
oil wells. Production from gas wells pre-
sents operators with some technical
problems not encountered in oil pro-
duction. Gas migration, where hydrocar-
bons move through the cement
between the annulus and the borehole
wall, is a common problem and can
only be overcome by improving the
quality of cement jobs. The risk of mas-
sive ‘kicks’ and well blowouts is much
greater in gas wells than in oil wells.
Safety procedures and well monitoring
must be of the highest standard.
However, fewer wells are required to
develop a gasfield than an equivalent
oilfield and in some cases gas from deep
reservoirs can be used to maintain pres-
sure in shallower oil and gas accumula-
tions. An excellent example of this tech-
nique is provided by Abu Dhabi’s Umm
Shaif Field.
Umm Shaif Field
The Umm Shaif Field, located 135 km
northwest of Abu Dhabi (figure 2.15),
was discovered by the Abu Dhabi
Marine Operating Company (ADMA) in
1958 (shortly after Bab Field, which was
discovered earlier that year).
In 1962, Abu Dhabi’s first oil ship-
ment came from Umm Shaif. There are
huge gas reserves in this field and they
have been put to a variety of uses over
the years. An unique feature of this field
is that its gas reservoirs contain all of
the major gas types: dry free gas, wet
free gas, gas condensate and associated
solution gas.
Most of the gas produced at Umm
Shaif is transported to Das Island through
35 km of a 30 inch gas line. There are two
separate gas liquefaction 'trains' operat-
ing at Das Island and a third is scheduled
for commissioning in 1994.
The gas train process can be divided
into five basic stages; compression,
sweetening, drying, cooling and lique-
faction. The Das Island plant is one of
the most advanced in the world,
equipped to handle natural and petro-
leum gases supplied at five different
pressures.
Structurally, the Umm Shaif Field is a
domal anticline with a vertical closure
of approximately 1400 ft, and an areal
closure of around 500 square km at the
main oil reservoir, Arab-D. Evaporites
(figure 2.16) play an important part in
oil and gas accumulation at this level.
Structural growth, which started early in
Fig. 2.15: Abu Dhabi’s producing oil and gas fields. Bab Field and Umm Shaif
were the earliest discoveries, both being found in 1958. The first oil shipment
came from Umm Shaif four years later.
Fig. 2.16: BREAKING THE SEAL: The Hith Anhydrite, an evaporitic layer overlying the
Arab reservoirs, is the major seal in Abu Dhabi. It prevents gas migrating into overlying
Cretaceous reservoirs. Thick shales are the other effective type of seal in the region.
Ibra
him
Mar
zouk
, AD
NO
C
Number 15, 1994. 41
the Jurassic, was caused by the move-
ment of Precambrian salt deposits.
These tectonic movements continued
until the Tertiary.
The crest of the field is cut by sev-
eral faults which influenced vertical oil
migration from Jurassic source rocks to
the Lower Cretaceous Thamama reser-
voirs. These faults reduce reservoir
continuity, and complicate secondary
recovery projects.
Routes to the reservoir
The Upper Jurassic Diyab Formation is
the main source rock for Umm Shaif
Cretaceous and Jurassic oil and gas
reservoirs. These reservoirs were origi-
nally filled with black oil during the
early stages of migration and source
rock maturation, approximately 90 M
years ago. At a late stage of maturation
the source rocks were buried beneath
oil-generating depths and started to pro-
duce gas. This gas migrated into existing
reservoirs and replaced some of the
entrapped oil. This ‘late gas charge’ gen-
erated the giant gas reservoirs of the
Middle Jurassic (figure 2.17), but did
not reach the Cretaceous Thamama
reservoirs.
Gas
5000
(ft)
10,000
Thamama reservoirs
Araej and Uweinat reservoirs
Arab reservoirs
Khuff reservoirs
Pre-Khuff potential reservoirs
15,000
Oil
W E
Hith Anhydrite seal
Deep Silurian shale source rock
Fig. 2.17: HIDDEN
DEPTHS: Umm Shaif
Field consists of several
stacked oil and gas
reservoirs. High-pressure
gas from the Khuff
reservoirs is being
pumped into the shallow
reservoirs to counteract
the pressure drop
associated with
production. Khuff gas is
playing a major part in
increasing overall field
efficiency and will
eventually be produced
from the shallower
layers into which it has
been pumped.
In contrast to the Mesozoic reser-
voirs, the older Palaeozoic Khuff and
Pre-Khuff reservoirs were sourced from
a Silurian shale. Maturation probably
occurred 50 M years ago, before the
Jurassic rocks entered the mature stage.
Khuff and Pre-Khuff structures were
probably oil-filled during the very early
stages of maturation and migration, but
this situation changed radically when a
late gas charge completely replaced the
oil. Thermal degradation of heavy com-
ponents ensured the development of
dry gas reservoirs.
Under pressure
Reservoir management at Umm Shaif is
developing into a sophisticated series of
gas injection projects. In simple terms,
high-pressure gas from the deep Khuff
reservoirs is being used to maintain
pressure in reservoirs in the younger,
overlying formations. Pressure drops
have occurred in these shallow oil and
gas reservoirs as a result of hydrocar-
bon production.
At present, Khuff gas is being injected
into the Uweinat gas reservoir in order
to maintain pressure and compensate
for the large off-take. In the near future,
Khuff gas will be injected into the Arab-
D gas cap to maintain the pressure in the
oil rim which is the main oil-producing
reservoir in the field. Reservoir man-
agers have also planned injection of
Khuff gas into the Thamama oil reser-
voir to maintain reservoir pressure.
A small fraction of the gas produced
from Umm Shaif Field is harnessed for
power. Gas flaring is kept to a minimum.
This represents a significant improve-
ment on the gas use patterns of the late
1970s, when large quantities of gas were
flared every day.
This summary of gas in Abu Dhabi was taken from:
Ibrahim Marzouk (1989) Geohistory Analysis: A Key for Reser-
voir Fluid Distribution, Abu Dhabi, UAE. MEOS SPE 18010.
Ibrahim Marzouk (in press) Abu Dhabi Gas Reservoirs - A
Geological Perspective. ADSPE 103.
Special thanks to ADNOC specialists who are
planning the development and management of
Umm Shaif Field.
Middle East Well Evaluation Review42
A difficult phase
Umm Shaif Field contains several gas
reservoirs, with varying compositions
occurring at different pressures (figure
2.18). The gas accumulations within this
single field display wet and dry charac-
teristics. How can we sample each
reservoir accurately to piece together a
coherent picture of the field?
Sampling errors or inaccurate phase
analysis lead to miscalculations of the
amount and composition of fluids in a
field. Development projects based on
flawed data could fail as a result of
these errors, with dramatic decreases in
a field's ultimate gas production.
To get the best results from a reser-
voir, engineers need to know the exact
composition of reservoir fluids at reser-
voir conditions. In the past, downhole
fluid sampling has often been hampered
by mud contamination during drilling.
Conventional tools offer two sample
chambers for each run into the hole, but
the samples can only be analyzed when
the tool has returned to the surface.
The most important aspect of phase
analysis is collecting the right sample -
one which accurately represents forma-
tion conditions. The development of
new wireline testers, such as the Modu-
lar Dynamics Formation Tester (MDT*)
tool, offers the chance to revolutionize
our understanding of phase behaviour
in complex reservoirs. This tool allows
the operator to monitor fluid quality as
it enters the flow line. The operator can
return contaminated fluids to the bore-
hole and wait for clean formation fluid
to enter the tool. When this happens the
clean sample can be diverted to one or
more of the tool’s six sample chambers.
The MDT tool allows the operator to
collect samples from several depths
during one trip down the hole. Each
sample chamber is detachable and can
be delivered to a laboratory for
pressure -volume - temperature (PVT)
analysis. One of the major advantages
with the MDT tool is its controlled draw-
down. This feature allows fluid sampling
which does not appreciably alter tem-
perature/pressure conditions in the
reservoir.
In the past, chemical analysis of fluids
from gas condensate reservoirs was one
of the most difficult problems facing
reservoir engineers. In saturated reser-
voirs, obtaining a representative sample
was almost impossible, due to limitations
of the sampling equipment used at that
time. This older generation of tools cre-
ated pressure drawdowns to bring fluid
into the sample chamber. The draw-
downs often caused gas to condense and
some of the condensate to be left behind
in the reservoir's pore system.
Thamama
Araej
Arab
Khuff
Pre - Khuff
Wet gas Dry gas
Depth
Bla
ck o
il
Vo
lati
le o
il
Temperature
Pre
ssur
e
Fig. 2.18: PHASE FACTS: Pressure and temperature both increase with depth: a trend
illustrated by Abu Dhabi's gas reservoirs. The pre-Khuff reservoirs contain dry gas,
while the Khuff and Araej reservoirs contain a mix of dry and wet gases. Shallow,
associated gas caps contain wet gas, with some of the Arab reservoir fluids close to
critical fluid composition.
Repeat samples from a gas conden-
sate reservoir (figure 2.19) using the
MDT tool show a very high degree of
repeatability. The survey at Umm Shaif
also indicated that there was no oil rim
under the gas: critical information for
the early stages of reservoir develop-
ment planning. Data from the MDT tool
can be used to correct early DST data
from older wells. In new wells, the DST
information can be dispensed with in
favour of the cost-effective MDT survey.
100
CO2N2 C1 C2 C3 i-C4 n-C4 i-C5 n-C5 C6 C7+
10
1
0.1
0.01
Sample 1Sample 2
Sample 3Sample 4
Com
posi
tion
(mol
e%)
Component
Fig 2.19: REPEAT PERFORMANCE: The sampling repeatability which can be obtained
using the MDT tool demonstrates that it is capable of collecting samples which reflect
the true composition of reservoir fluids.
In thick gas reservoirs early evalua-
tion of condensate volume and composi-
tion are critical. Temperature and pres-
sure increase with depth, and there can
be significant differences between upper
and lower compartments of a single gas
reservoir. Lateral variations are common
in reservoirs and compartments at the
same depth can be subjected to lateral
pressure or temperature differences.
Number 15, 1994 43
Looking a little deeper
There are many occasions when the
ability to detect gas without formation
density measurements is invaluable.
Roughness in the borehole wall or thick
mudcake often has little effect on the
neutron log while the very shallow den-
sity measurement is completely dis-
torted under these conditions. In some
boreholes, downhole conditions prevent
the use of a tool string carrying a chemi-
cal source. In cased holes the casing and
cement make density measurements
unreliable.
The Integrated Porosity Lithology
System (IPLS*) tool can distinguish gas-
bearing layers from tight zones, through
the casing and cement. The chemical
neutron source in this tool has been
upgraded to image more of the forma-
tion (and its reservoir properties) by
looking further beyond the borehole
environment.
Capture sigma(CU)10 40
Caliper(IN)8 18
Gamma ray(GAPI)0 100
0.0
0.0
2.71
Far epithermal neutron(PU)60.0
Array epithermal neutron(PU)60.0
Formation density(g/cm3)1.71
Gas indication from array/Far epithermal neutrons
Gas indication from density/Array epithermal neutron
x690
x700
x710
x720
x730
Clearly, the new IPLS system is a
more effective tool than conventional
neutron logs. However, the modified
neutron source in the IPLS offers a sec-
ond advantage: enhanced safety. Well-
site safety is vital to everyone associated
with the petroleum industry. Gas detec-
tion has generally relied on neutron log-
ging tools which have a chemical neu-
tron-generating source. In the past, this
could only be deactivated once it had
been removed from the borehole. While
the tools were effective, the potential
hazards associated with regular expo-
sure to neutrons were well known.
The re-designed neutron source in
the IPLS tool has introduced new levels
of safety for neutron logging tools. The
source in this tool can be switched off
before it is removed from the borehole.
Testing tested
The first priority for the improved system
was testing under field conditions. An
8.5inch borehole was drilled through a clean,
gas-bearing sand and an underlying shaly
zone (figure 2.20). Porosity was evaluated for
both layers using Accelerator Porosity Tool
(APT*) and Compensated Neutron Log
(CNL*) techniques.
If the original pore fluid in a 30 pu
sandstone is water (with a density of
1.0 g/cm3) and this water is replaced by
gas (with a density of 0.1 g/cm3) appar-
ent grain density for the rock will be
reduced from 2.65 g/cm3 to 2.15 g/cm3.
This density reduction or ‘excavation’
effect lowers the APT near-to-far ratio
porosity (or the CNL porosity) by more
than can be attributed to the decrease in
hydrogen index from water to gas. The
near-to array ratio porosity is virtually
insensitive to grain density changes, and
will read the true hydrogen index.
The log from the test well showed that
the stand alone APT gas indicator detected
all occurrences of gas recorded on the
conventional neutron-density overlay.
Shales in the sandstone increased
grain density and removed the density-
reduction effects of gas from the (CNL)
far detector. This indicated that the APT
was required only for clean sandstone
reservoirs.
In the past, neutron-sonic overlays
have supplemented density data for
porosity, lithology and gas evaluation.
When used with a neutron porosity
derived from CNL, shale effects tend to
displace both sonic and neutron poros-
ity data towards higher porosities, mak-
ing the neutron-sonic overlay method
unreliable in shaly zones.
Shaliness causes other problems in
quick-look lithology evaluation using
CNL neutron-density overlays. Informa-
tion about the degree of shaliness is
often needed. Introducing the APT neu-
tron porosity technique to measure total
formation hydrogen index, even in
shales, greatly simplifies evaluation.
Fig. 2.20: BIGGER, DEEPER, SAFER, BETTER: Modifying the neutron source in the IPLS tool has
helped to introduce new standards in safety for neutron logging tools. This source can be switched
off before the tool leaves the hole. This represents a significant reduction in neutron exposure for
wellsite engineers. The gas indicator from the Array and Far epithermal neutron measurements is
especially important for cased wells where the data from density tool is much less reliable.
Middle East Well Evaluation Review44
Delivery and storage
Once gas has been recovered from a
field it undergoes a complex chain of
processes to prepare it for the con-
sumer. Natural gas must be cleaned or
‘scrubbed’ to remove undesirable com-
ponents such as carbon dioxide (CO2),
hydrogen sulphide (H2S), heavy hydro-
carbons (aromatics) and trace elements
such as mercury and arsenic. Separation
processes can be divided into the partial
removal of components present at rela-
tively high concentrations (e.g. bulk
removal of CO2), and almost complete
removal of components present at rela-
tively low concentrations (e.g. H2S).
Very high purity levels can be obtained
using commercial scrubbing processes,
though the flow rate is often limited if high
purity is required. Recent research has
focussed on developing new and compact
gas scrubbing techniques.
Unfortunately, although gas is usually
clean and easy to produce cost-effec-
tively, transportation can be difficult and
expensive.
Gas delivery
Gas is transported in two ways - by
pipeline, or as liquified natural gas in
LNG tankers (figure 2.21). In the past, gas
distribution efforts have concentrated on
pipeline networks but there are several
indications that this may be changing:
• According to Cedigaz, the international
gas information organization, there are
clear signs that natural gas markets
which can be serviced by pipeline are
reaching saturation point.
• The growing distance between
reserves and markets implies that
pipelines may soon reach their techni-
cal or economic limits.
• Most of the gas -exporting countries,
which have traditionally relied on
pipelines for distribution, are reaching
the limits of their export capacities. No
major onshore exporter has emerged on
international markets since the late
1970s.
• Importing countries want to diversify
supply sources and, given the restricted
number of pipeline exporters, more dis-
tant LNG suppliers are becoming more
strategically attractive.
• The emergence of remote gas mar-
kets, which have good potential but are
located some distance from major gas
pipeline networks in Asia and Europe,
should encourage the development of
LNG receiving terminals rather than
pipeline connections.
• Increasing awareness that political
instability may threaten pipeline deliver-
ies, such as the recent gas pipeline cut-
offs in the CIS, add another dimension
to the pipeline - tanker debate.
Despite these problems gas pipelines
are still being built. A pipeline survey
recently carried out for the North Amer-
ican market predicts that more than
10,000 miles of gas transmission
pipeline will be laid in the United States
over the next five years. Even so, this
represents a drop from the period 1988-
1992 when more than 13,000 miles of
pipeline were laid.
LNG tankers
Shipping costs are a critical factor in
determining the viability of LNG pro-
jects. At present, there is no second-
hand market for LNG tankers and the
cost of building a new, 125,000 m3 vessel
has soared from $120 million (at the end
of 1986) to $270-290 million.
Drewry, the London shipping consul-
tant, forecasts further rises in construc-
tion costs for the following reasons:
• World shipbuilding capacity will
remain overstretched by the limited
number of yards with LNG construction
experience.
• Ship-building subsidies will continue
to be phased-out.
• Shipbuilders will face labour short-
ages and higher costs.
In this economic climate, ship own-
ers will probably concentrate their
efforts in increasing the working life of
vessels beyond the current 20-25 years
standard. This strategy will lead to a
gradual increase in global LNG carrier
capacity. While this approach may be
impeded by government safety regula-
tions, it seems certain that LNG will
gradually increase its share of the inter-
national gas market.
Fig. 2.21: A new generation of
LNG tankers will have to be
built to meet the demands of
an expanding LNG market.
This artist’s impression shows
a 68,000 tonne tanker which
will be delivered to the Abu
Dhabi National Oil Company
in 1996 by the Kværner Masa
Shipyards in Finland.
Art
ist’s
impr
essi
on c
ourt
esy
of G
ulf N
ews
Fig. 2.22: There are two important methods for underground gas
storage. The first sets up a flow gradient, sucking groundwater into an
unlined cavern (a). This water is pumped out from the lowest part of the
cavern in order to preserve a hydrodynamic seal. The second, which has been
applied in areas where there are few stable rock masses, involves lining the cavern to provide
a physical barrier to water or gas migration (b). The sealing material must be non-reactive and
sufficiently durable to accommodate minor movements in the cavern wall.
Fractured or unstable rock
Unreactivesealingmaterial
No groundwatercontamination
Seal intact after movement
on fracture plane
LNG
Lined
Number 15, 1994 45
Going underground
In 1984 a Liquified Petroleum Gas (LPG)
tank in Mexico City caught fire and
exploded with catastrophic results.
Safety and environmental concerns aris-
ing from accidents such as this have
stimulated interest in underground solu-
tions for long-term storage of liquid
hydrocarbons.
Underground storage started with the
development of caverns in natural salt
formations. These are relatively inex-
pensive to develop and manage, but
the development of large salt deposits is
limited.
Hard rock caverns are being devel-
oped and fall into two main categories:
lined and unlined caverns. In Scandi-
navia, the option best suited to regional
geology is the unlined cavern (figure
2.22a). This requires a ‘hydrodynamic
seal’. Controlled pumping of water from
the deepest point of the cavern sets up a
seepage gradient in surrounding rocks.
This gradient, ensures that fluids flow
towards the cavern, preventing the
stored product from penetrating the
rock formation. Unsupported caverns of
this type require stable rocks.
water
Stablerock mass
Water pumpedout to maintain
seepagegradient
LNG
Unlined
NAME YOURPOISONNatural gas often contains small, but
significant traces of unwanted or toxic
substances. Some of the substances,
such as hydrogen sulphide, are quite
common in gas deposits and can be
dealt with relatively easily. Other com-
ponents, such as mercury and arsenic
compounds, are less common and
treatment in gas plants is not routine.
Mercury is typically found in con-
centrations between 1mg/m3 and
200mg/m3. The potential dangers of a
high mercury content in gas were not
recognized until 1973 when the cata-
strophic failure of aluminium heat
exchangers occurred at the Skikda
LNG plant in Algeria. Investigations
identified mercury as the corrosive
element.
Arsenic, the 20th most abundant
element in the earth’s crust, is
extremely toxic. Any loss of contain-
ment where arsenic-bearing natural
gas was involved would represent a
serious health risk to anyone in the
affected area. Marine animals are
known to concentrate arsenic in their
bodies and the arsenic found in crude
petroleum probably comes from this
source.
Clearly, the composition of gas
from any particular reservoir must be
known before production can begin.
Special precautions (figure 2.23) or
cleaning techniques may be neces-
sary. In some cases the special
arrangements required for sour or
toxic gas accumulations will make pro-
duction uneconomic.
A major problem with hydrodynamic
seals is the contamination of stored
hydrocarbons with fungi and bacteria
from the seepage water. Conversely,
water pumped from the bottom of the
cavern will contain a small amount of
the stored hydrocarbon. These fears
over ground water contamination, cou-
pled with the shortage of stable rock
masses, make the ‘Scandinavian Storage
Concept’ unsuitable for central and
southern Europe.
The lined hard rock cavern (figure
2.22b) is essentially a sealed chamber.
Clearly the lining must be capable of
sealing for a long period of time and
must be chemically compatible with the
stored liquids. In central Europe, where
rock stability is typically much lower
than in Scandinavia, the lining must also
be capable of retaining its seal after rock
movements.
(a) (b)
Fig. 2.23: HANDLE WITH CARE: Gas
accumulations which contain toxic
substances such as mercury or arsenic
must be handled with care until the
cleaning process is complete. The special
safety precautions which are required
can seriously affect the economic
viability of a gasfield.
10-3 10-2 10-1 100 101 10210-2
10-1
100
101
Elapsed Time (hr)
No
rmal
ized
pre
ssu
re c
han
ge
and
der
ivat
ive
(psi
/BO
PD
)
Middle East Well Evaluation Review46
Support at every step
Gas production is a complicated
process. There are many stages between
drilling the first gas well in a reservoir
and conducting production tests.
One of the most important
advances in well testing technology is
a system which allows you to get data
out of the well before removing the
drill string.
The DataLatch system (figure 2.24)
can accomplish this in two ways. The
first option is data recording in the
hole, and the alternative is real-time
data transmission direct to the surface.
This transmission feature allows the
operator to monitor downhole condi-
tions as the test proceeds (figure 2.25).
Using DataLatch, the operator can
monitor three separate pressure sen-
sors. These can be used indepen-
dently to measure pressure below the
flow control valve in the tests string,
above the valve or in the annulus.
The system can run in conjunction
with the 5 inch TCP strings normally
used to perforate 7 inch casing. This
means that perforation and well testing
can be accomplished in a single trip,
with pressure being measured from
the moment the well begins flowing.
Low level pressurecommand pulses
Well casing
Commandimplementation
Independently operatedcirculating valve
Flow control valve
Test string
Sensor Test string
Test zoneTest zonep
t
Wireline
Test string
LINC housing
MSRT tool
Flow-control valve
Selective portingPressure transducers (3)
Electronics
Battery
Inductivecoupling
Latch
Wirelinerunningtool
LatchedInductiveComputer(LINC)
Fig. 2.26: IRIS downhole tools are mechanically simpler than
conventional tools which require high pressure levels, high
test string operating torque or gross tests string weight.
IRIS offers simple and flexible string control and allows more
services to be performed in a single trip.
Fig. 2.24: The DataLatch system allows
downhole recording and surface readout of
pressure and temperature data during flow
or stimulation.
Fig. 2.25: Real-time transmission of data allows the operator to ensure that test
objectives have been met before the tool is removed from the well. This
guarantees that buildup tests performed using the DataLatch system are neither
prolonged unnecessarily nor ended prematurely.
Number 15, 1994. 47
Fig. 2.28: SMOKELESS FUEL:
The Green Dragon (a) in
action during an offshore test.
This burner design comprises
a monitoring system which
gathers pressure, temperature
and flow rate data. The
atomizers and burner
orientation are controlled by
special remote-control
actuators. This has proved a
valuable safety feature.
Conventional burning
techniques (b) are not so
efficient and cause more
hydrocarbon fallout.
Simple and safe drillstem testing
Conventional drillstem testing tools
require high pressure levels, test-string
operating torque or gross test-string
weight.
Intelligent Remote Implementation
System (IRIS*) tools are mechanically
simpler, require less energy and are
controlled by low-energy pressure
pulses moving through the mud inside
the casing. The controller, which oper-
ates the tool hydraulic system,
responds to coded command signals
from the surface (figure 2.26).
There is no wireline or surface actu-
ated mechanical connection: the com-
mand signal is transmitted down the
annulus fluid as low-amplitude pressure
pulses. This approach represents a radi-
cal simplification of test string control.
The new system allows more services
to be performed in a single trip, while
increasing safety and tool reliability.
Separate answers
High-efficiency, vertical cyclone separa-
tors (figure 2.27) are approximately one
third the size of conventional separa-
tion systems. The gas stream enters the
separator at a tangent, an arrangement
which sets up the cyclonic action -
throwing any liquids against the wall of
the vessel. As the gas leaves the separa-
tor a low pressure area is created by the
cyclone effect. This low pressure area is
used to provide suction which drags
remaining liquids to the lower portion of
the separator vessel. When used under
design conditions, the cyclonic separa-
tor will remove 99.9% of all free liquids
and solids larger than 5 microns.
Clean Green Dragon
During production tests it is often neces-
sary to flare some oil or gas. There have
been dramatic improvements in hydro-
carbon flaring systems over the years,
particularly in burner efficiency and
safety. The latest breakthrough in off-
shore hydrocarbon burning is the Green
Dragon* (figure 2.28).
The first quantitative study of hydro-
carbon fallout from burner flames was
carried out in 1991. In these tests fallout
was evaluated by burning a known vol-
ume of oil at a pre-determined rate. The
oil and the fallout from the flame were
chemically ‘finger-printed’. Unburned oil
was evaporated in stages, with the com-
position of each stage analyzed and plot-
ted until residue and fallout ‘finger-print’
matched. Burner efficiency can then be
estimated by calculating the volume of
unburnt hydrocarbon within a specific
area of the fallout zone.
Rigorous testing in the laboratory
and in the field shows that the Green
Dragon is the most efficient offshore
burner available. The clean, soot-free
flames which the system produces vir-
tually eliminate hydrocarbon fallout
around a production platform.
Efficient flames
The key to clean burning is getting the
fuel - air mixture just right. The important
part of the Green Dragon in this respect is
the hydrocarbon outlet nozzle. Atomiza-
tion is carried out in two stages. Pressure
creates a vortex which accelerates the oil
towards a nozzle opening where the liq-
uid is sheared into finely atomized
droplets. At the same time, a compressed
air jet provides the additional energy
required for further atomization. Com-
pressed air leaves the nozzle in a high-
speed vortex at a velocity close to the
speed of sound (330 m/sec at sea level).
The compressed air hits the oil jet, accel-
erating the droplets. The high velocity
creates turbulence in the surrounding air
which produces a pressure profile across
the flame. This sucks extra combustion
air into the flame which leads to higher
temperature burning and a cleaner flame.
Fig. 2.27: The vertical
cyclone separator is
approximately one third the
size of more conventional
separator systems. The gas
stream enters the separator
at a tangent, throwing liquids
against the wall of the vessel.
This device will remove
99.9% of all free liquids and
solids larger than 5 microns.
(a)
(b)
Middle East Well Evaluation Review48
One of the most common problems in
gas wells is gas channelling. This is the
movement of gas in the cemented annu-
lus of the well. The problem is more
common than it need be since good
cementing practice can prevent it.
Incorrect cement mixing, poor mud
removal, chemical shrinkage of cement,
dehydrated cement or gelled cement
and free water can all contribute to the
problem.
Studies carried out at Dowell's
research and development centre in
France have shown that gas from a pres-
sured formation will flow into the
cement in the annulus once the hydro-
static pressure of the cement slurry
drops below formation gas pressure.
Hydrostatic pressures in cement always
drop sharply during the setting process.
Cementing the relationship
Several techniques have been tested to
deal with the specific problems encoun-
tered in gas wells. Efforts to reduce the
risk of gas channelling usually rely on
one or more of the following methods:
• Minimizing the height of the cement
column,
• Increasing the annular mud density,
• Adjusting the slurry-thickening times,
• Conventional multi-stage cementing,
• Applying pressure to the annulus,
• Increasing the water density of the
cement slurry mix,
• Modifying the cement slurry.
The first four methods are all aimed
at maintaining a high hydrostatic pres-
sure on top of the cement column to pre-
vent gas migration.
The next two techniques are of little
use in gas-migration control. Downhole
pressure measurements carried out dur-
ing setting indicate that the cement col-
umn does not transmit applied annular
pressure. Increasing the mix water den-
sity is not an answer since this approach
assumes, incorrectly, that the pressure
gradient of a setting slurry falls no lower
than that of its mix water density.
The last technique, using an additive
to prevent gas channelling or otherwise
modify the cement is the approach
adopted by Dowell's Gasblok cement
system. The method was first developed
more than a decade ago, but has
evolved from a single product to a com-
plete gas migration control system.
Modifying the cement slurry is a logi-
cal approach. Since we cannot prevent
gas from entering the cement, we must
concentrate on preventing the gas going
any further. Gasblok incorporates a latex
additive which forms an impermeable
film when it encounters gas.
Latex limitations
The latex particles used in the Gasblok
method are fully dispersed in the
cement slurry when it is pumped and
stabilized so that they remain separate
until the cement sets.
Latex compounds are unstable and
most of the group would be totally
unsuitable for the downhole environ-
ment. They are sensitive to mechanical
energy, electrolytes and high and low
temperatures. When destabilized they
flocculate into agglomerates. Therefore,
choosing a latex which can be mixed
and pumped at high shear into wells
with variable temperature and chem-
istry, is not a simple process. The
selected latex must be tough enough to
survive storage, high temperatures, low
temperatures or several freeze-thaw
cycles.
One of the first tests for the latex
additive in Dowell’s Gasblok system was
in a gas production/storage field in
Europe. Annular gas flow had devel-
oped into a major problem and the
workovers were proving lengthy and
expensive. Although the wells were rela-
tively shallow (about 1000m), the
cement job was made more difficult by
the presence of gas streaks and the
well’s high deviation (16° to 50°).
After cementing a 7inch production
casing with Gasblok, all annular gas flow
stopped. Wireline surveys can reveal
the difference between good and bad
cement jobs. The results from this well
were confirmed by logs which indicated
strong cement bonds to both the casing
and the formation. The latex seal had
formed perfectly.
Other methods designed to modify
the cement slurry - compressible
cements, expansive cements, ‘right-
angle setting’ cements and thixotropic
cements - can be applied in some cases,
but have been less successful. Com-
pressible cements (particularly foamed
cements) are often restricted to shallow
depths while gas-generating cements are
difficult to control. Expansive cements
Fig: 2.29: BUBBLING
UP: The gas bubbles
reaching the surface
a short distance
from this drilling rig
present a major
safety hazard. Gas
escapes such as this
can undermine the
drilling rig or result
in explosive
cratering of the
seabed.
Fig. 2.30: THE HOLE STORY: This log shows the type of mechanical
damage which can release hydrocarbons from the casing. Gas lost
into the cement layer can cause severe damage to the well.
Perforations
Mechanical damage
Nea
l Ada
ms
Fire
fight
ers
AVOIDING THE CEMENT LAMENT
(b)
x400 ft
x300 ft
Number 15, 1994. 49
are suitable for filling small gaps
between the cement and the formation
or the casing, but are unlikely to fill the
channels opened up by gas migration.
Right angle setting cement is designed to
make the transformation from liquid to
solid so quickly that gas invades only a
small part of the cement column. These
are effective in maintaining hydrostatic
load right up to the beginning of set, but
could be improved with additives.
Seeing the gas
The danger of gas channelling within
cement is illustrated by the arrival of gas
at the surface, a short distance from a
drilling rig (figure 2.29). In the past, the
ability to identify casing damage (figure
2.30) helped operators to predict where
gas entry was a problem.
The point at which gas actually
enters a well and its distribution behind
the casing can now be resolved using
ultrasonic imaging. High resolution
images of casing condition and the qual-
ity of cement between formation and
casing are very important factors in the
control of gas channelling. The rotating
transducer contained in the Ultrasonic
Imager Tool (USIT*) provides 3D images
around 360° of the borehole.
Channels are revealed by variations
in the acoustic impedance of the mater-
ial behind the casing. A water-filled
channel in casing cement appears as a
blue area on a cement map (figure
2.31a). Gas channels are easier to detect
than water channels, since gas has a
much lower acoustic impedance than
water, drilling mud or cement. On the
cement map (figure 2.31b) gas is indi-
cated in red.
The gas entry mechanism and its
route to the surface are not always obvi-
ous without the benefit of a USIT tool
survey. In some cases gas may move up
the casing to the surface, while in other
situations gas has migrated behind a
cemented liner rather than the casing.
Casing condition can be evaluated
using the USIT tool, which measures
internal casing diameter and thickness.
Severe damage on the inside of the cas-
ing disperses the acoustic signal, result-
ing in lower acoustic amplitudes which
appear as dark areas on the amplitude
image. Higher resolution of casing condi-
tion can be obtained by modifying the
USIT tool to make it function like a UBI
tool. In this modified form the tool will
identify holes in casing and can be used
in non-cased holes to evaluate the
acoustic character of the reservoir rock.
It is especially useful for detecting frac-
tures or vugs, even in wells drilled with
oil base muds.
(a)
x300 ft
x250 ft
bonded
bonded
liquid
gas
gas
liquid
Gas index(USGI)
0.0 1.0
Gas index(USGI)
0.0 1.0
Fig: 2.31: GAS IS RED, WATER IS BLUE: Water channelling (a) and gas channelling (b) in
downhole cements are a major problem in many oilfields. Severe corrosion or
mechanical damage to the casing can release reservoir fluids into the cement layer,
where they can cause a great deal of damage. Good cement jobs help to minimize
channelling effects but in cases where the damage has been done, remedial action such
as a Gasblok treatment may be needed.
Middle East Well Evaluation Review50
are being introduced. In 1988 federal
requirements called for a reduction in
sulphur content to 0.05 wt %. This com-
pares with a current industry average of
0.3 wt %. The Californian specifications
also exceed federal guidelines by
demanding steep cuts in the aromatic con-
tent of diesel, which currently averages
30% - 31% by volume. From October 1
1993 this has been further reduced to
10vol% for large refiners and 20vol% for
small independent refiners.
As emission targets for fuels become
increasingly stringent we may see a large
market develop for synthetic ‘super diesel’
or ‘super kerosin’, which offer smoke
points above 100 mm and no sulphur.
Estimates of syn - fuel production
costs suggest that modern conversion
processes will only be viable when the
oil price rises above $ 25 / bbl. How-
ever, it is always difficult to accept
such general figures before engineering
studies have been made for specific
sites and plant. It is clear that the suc-
cess of future syn- fuel projects will be
strongly influenced by the future price
of crude oil.
Changing fortunes:transforming natural gas
Natural gas is a clean, efficient fuel.
Why, then, has so much technical effort
been applied to the production of syn-
thetic fuels (or ‘syn- fuels’) from natural
gas, especially when the conversion
process involves energy loss?
There are several technical, political
and environmental reasons for trans-
forming natural gas into synthetic fuels:
• In the case of ‘shut-in’ gas fields which
are situated a long way from a pipeline
or potential market, syn- fuel production
could be a cheaper or easier option
than LNG processing.
• Political support for synthetic fuels
focuses on crude oil pricing and global
supply. Many countries have imple-
mented policies to develop syn-fuels in
an effort to put a ceiling on oil prices.
• An important factor in some coun-
tries, is the environmental benefits of
synthetic fuels. Most of the synthetic
fuels derived from natural gas conver-
sion (e.g. methanol) are high quality,
clean-burning fuels.
Early days
Modern efforts to synthesize fuel from
gas began in Europe earlier this cen-
tury. In the 1920s research findings
under the title ‘How to produce mineral
oil from carbon monoxide and hydro-
gen’ were published by two German sci-
entists, Franz Fischer and Hans Trop-
sch. Their research led to intensive
activity in Germany throughout the
1930s and during the Second World War
(1939 - 1945). All of this research was
aimed at making Germany less vulnera-
ble to oil shortages.
Methods and products
Natural gas, with methane (CH4) as its
main constituent, is rich in hydrogen.
However, methane is a very stable mol-
ecule and conversion to other products
(figure 2.32a) calls for severe physical
and chemical conditions to convert
methane to ‘synthesis gas’.
Synthesis gas - a mixture of carbon
monoxide (CO) and hydrogen (H2), with
smaller amounts of carbon dioxide
(CO2) and water (H2O) - is an important
intermediate in the liquid hydrocarbon
production process. Conversion tech-
niques which involve the synthesis gas
step usually transform 50 % of the syn-
thesis gas to water.
The original Fischer-Tropsch process
involved use of a water-cooled reactor
containing more than 2200 double tubes
filled with cobalt catalyst. These con-
verted the synthesis gas into liquid
hydrocarbons. Steam reforming and par-
tial oxidation processes typically form
the basis of synthesis gas production in
modern reforming plants.
The best known syn-fuel technique of
the 1980s is probably Mobil’s MTG
(Methanol To Gasoline) process (figure
2.32b). This technical and economic suc-
cess led to a 600,000 tonne/year produc-
tion unit being set up in New Zealand.
Distillates from natural gas
Long chain, waxy paraffins (alkanes) can
be produced using an updated Fischer -
Tropsch reaction. In this modern process
catalysts are selected with the aim of pro-
moting carbon chain growth to make
waxes. The alkane wax can then be
hydrocracked to give middle distillates.
The fuel properties of these products are
excellent. Both Statoil and Shell report
very high quality products using their
own methods. This fuel can be used
either as a blendstock for other products
or as a premium fuel for cars and trucks.
In California - the state which often
leads the United States on environmental
issues - tough new diesel specifications
Fig. 2.32: Natural gas has found
applications in many industrial
sectors (a). The ease with which gas
can be transformed to liquid fuel and
its high burning efficiency make it an
attractive option for a wide range of
industrial users around the world.
Mobil’s ‘gasoline’ from natural gas
process (b) is one of the best known
‘syn-fuel’ methods.
Ole
fin
s
Met
han
ol
Oth
ers
Fu
els
Ad
dit
ives
Gas
en
gin
e
Gas
Po
wer
Co
mb
ined
Cyc
le
Gas
en
gin
e
Fu
el c
ells
Eq
uip
men
t
Gas
bu
rner
Liq
uif
acti
on
Sto
rag
e
Tra
nsp
ort
atio
n
CatalysisProcesses &equipment
CombustionProcesses &equipment
LowtemperatureProcesses &equipment
Petrochem.industry
Transportation Power andenergy
Industry LNG
Natural gas technology
Natural gas
Application
Technologyarea
Steam
Nat. gas
Ref
orm
er
Met
hano
l rea
ctor
DM
E r
eact
or
Gas
olin
e re
acto
r
Synthesisgas Methanol DME
Water Gasoline
(b)
(a)
Number 15, 1994.51
Fig. 2.34: This
complete sampling
and transfer system
can identify a range of
gas components (a)
then group
compounds into
normal alkanes, iso-
alkanes, cyclo-alkanes
and aromatic types.
The transfer bench
(b) complies with all
environmental
regulations and is
mercury-free.
Component
identification (c) is
vital for production
planning.
Chemical compositions
There is a wide range of hydrocarbons
and related organic compounds (figure
2.33). While chemical differences are
clear in the laboratory, sample collec-
tion from the well has not always been
reliable. The most important aspect of
fluid characterization is collecting the
right reservoir fluid from the right part
of the reservoir. However, the way in
which the sample is collected can have
a direct bearing on analytical results.
Accurate PVT analyses depend on col-
lecting reservoir fluids without changing
the temperature or pressure of the flu-
ids during sampling.
The Schlumberger Sampling System
Pollution Free (SSSPF) unit is designed
to meet the challenge of downhole
sample collection and subsequent
transfer to surface and laboratory. The
system complies with all safety and
environmental requirements and is
mercury-free.
Most reservoir characterization
efforts are focused on the equations of
state (EOS). The Enhanced Fluid Analy-
sis System (EFAS) unit can identify and
quantify all components in a sample
containing compounds up to C20+ and
beyond (figure 2.34a). It also offers a
‘semi-detailed’ option which can group
compounds into Normal Alkanes, Iso-
Alkanes, Cyclo-Alkanes and Aromatics.
The unique design of the sample
bench (figure 2.34b) allows simple and
safe sample transfer from wellsite to lab-
oratory. This type of system can save a
great deal of time in characterization of
complex fields where there are marked
variations between individual reser-
voirs (figure 2.34c).
The detailed information which is
now available allows the user to gener-
ate a range of PVT data using a number
of mathematical models. The main field
applications for this system are; surface
installation design, Enhanced Oil Recov-
ery (EOR), gas cycling projects etc. In
future these will be complemented by
fluid production and reservoir composi-
tional mapping applications.
Petroleum hydrocarbons
LipidsProteins Wood
CelluloseC6H10O5
Cane sugar
0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1 0
1
2
HC
Diamond
CoalLignite
Peat
Inert carbon
3
4
OC
Mixed marinesourced oil
Natural gas
MethaneCH4
EthaneC2H6
Butane
Algalsourced
oil
GlucoseC6H12O6
Fig. 2.33: GAS, SUGAR AND DIAMONDS: The variation of hydrogen:carbon and oxygen:carbon
ratios determine the physical and chemical properties of organic compounds.
A major Middle East field
Reservoirs Type Gas composition (%)
C1 C2+ C7+ H2S
Upper zone Cap gas 67 25 5 2
Middle zone Gas reservoir with
minor oil rim 77 14 0 3
Lower zone Free gas reservoir 88 4 0 1.3
C4 C5 C6 C7 C8 C9 C10 C11Pseudo boiling point
type distribution
0
1
2
3mole%
0
5
10
15
20
25
30
35
40
45mole%
02 N2CO2
H2S CH4C2H
6C3H
8
Fluid molecularcomposition
C12+
(a)
(b)
(c)
Middle East Well Evaluation Review52
In the Greenhouse
Our planet is getting warmer, a trend
which may be an indication of troubles
ahead. The Sun is the source of virtually
all of the energy reaching Earth from
space. In the past a balance has existed
between the amount of solar energy
transmitted through the earth’s atmos-
phere and the amount reflected back
into space. For millions of years the
Earth’s average surface temperature
fluctuated gradually - sometimes warmer
sometimes cooler.
The most important ‘Greenhouse
Gases’ occur naturally in the atmos-
phere: water vapour, carbon dioxide
(CO2) methane (CH4), nitrous oxide
(N2O) and ozone (O3). However, many
of these gases are also released as a
result of human activities.
Burning of fossil fuels in cars and
power stations release the ‘Greenhouse’
gases. These gases change the Earth’s
heat budget by trapping infrared radia-
tion (heat) in our upper atmosphere
(figure 2.35).
Since the beginning of the industrial
revolution in Europe, atmospheric CO2
has risen from about 275 ppm to 353 ppm
today, an increase of more than 28 %.
One-third of this CO2 enrichment is due
to deforestation; the remainder has been
caused by emissions generated by fossil
fuels. These are now estimated to be
producing 22 - 26 billion tonnes of CO2
each year. However, combustion of oil
is not the major source of industrial CO2.
On average, coal produces almost twice
as much CO2 as an equivalent weight of
oil.
Some scientists estimate that atmos-
pheric CO2 will double between the
years 2030 and 2050. Climatic models
interpret this as a temperature increase
of between 1.5°C and 4.5°C. If surface
temperatures increase at rates between
0.5°C and 1°C every decade there will
be serious implications for humanity:
• Drowned cities. As the atmosphere
warms, polar ice caps melt, the volume
of seawater increases and sea levels
rise, inundating coastal cities.
• Environmental refugees. The inhabi-
tants of low-lying coastal areas, such as
the southeastern United States, may
have to leave their homes and find new
areas in which to settle. Resettling these
refugees may require the development
of wilderness areas and could precipi-
tate the destruction of forests.
• Stormy weather. Environmental scien-
tists have suggested that many of the
destructive typhoons, hurricanes and
floods which have occurred in recent
years have been influenced by global
warming.
• Water shortage. Shifting precipitation
patterns may lead to widespread water
shortages and droughts in areas which
have never been affected in this way
before. Serious droughts could affect
the grain belts of the United States,
Europe and Asia causing worldwide
food shortages.
If we accept predictions that the ris-
ing trend of world energy demand is set
to continue, what can be done to restrict
the amount of CO2 pouring into the
atmosphere?
Bring on the substitute
The world shifts continuously from one
energy resource to another (figure 2.36).
For thousands of years wood was the
most important energy source available
to man, but it was replaced by coal dur-
ing the western-world’s industrial revo-
lution. Coal was ultimately replaced by
oil as the world’s major energy source
during the 1960s. Today, natural gas is
the new challenger for global energy
dominance.
Nuclear power, although a rising
force in some regions, is not a global
solution and a dominant position for this
form of energy is much less certain than
it seemed in the 1960s and 1970s. Many
countries are reviewing their long-term
plans for nuclear power with a view to
reducing costs and risks.
Perhaps the most surprising aspect of
historical ‘energy substitutions’ is the
fact that they occurred while wood and
coal were still abundant. Could gas
replace oil in a similar fashion?
Fusion confusion?
Researchers at the Princeton University
Plasma Physics Laboratory in the USA
may be on the verge of a major break-
through in fusion power generation.
At the end of 1993, they produced
3 megawatts of power in an experimental
reactor: the largest controlled fusion
reaction ever. While this is an interesting
research development it can hardly be
described as the ‘dawn of a new era’. A
combination of fundamental engineering
difficulties and the availability of rela-
tively cheap fossil fuels means that com-
mercial fusion power stations will not be
built for many years.
Infra-red radiation
Solar radiation
Cooling
Stratosphere
(Warm
ing
Troposhe
Fig. 2.35: SOME LIKE IT
HOT: Environmental
scientists have not
reached agreement on
the long-term effects of
adding CO2 and other
greenhouse gases to the
atmosphere. However, if
surface temperatures
rise all over the earth we
can expect dramatic
changes in climatic
patterns and land use.
Number 15, 1994. 53
Taxing questions
Calls for a new carbon tax and other
energy taxes have been mooted in
countries throughout the industrial
world for several years. As the environ-
mental lobby grows, it seems inevitable
that there will be legislation to curb the
use of oil and coal. Such changes are
aimed at reducing global warming
effects and reducing other environmen-
tal and security problems which, it is
claimed, are associated with traditional
fossil fuel energy sources.
In effect, there will be an indirect
subsidy for all natural gas supplies
which will operate by discouraging
investment in competing fuels and, par-
ticularly, their use for electricity genera-
tion. As new taxes increase the costs of
coal and oil in consumer nations, expan-
sion of the LNG market to a central posi-
tion in world energy trade seems very
likely.
Some analysts suggest that it is the
environmental measures being pro-
posed at present which will precipitate
the move to gas - a shift which could not
be achieved during the 1970s and 1980s
by rising oil prices.
Gas for the motorist
Natural gas is the most environmentally
acceptable fossil fuel. At today’s prices
it is a cheap, clean and efficient energy
source equally suitable for domestic
and industrial use. Natural gas has
achieved good market penetration in all
sectors except transport. Although there
are nearly one million compressed nat-
ural gas (CNG) vehicles in the world
today, mostly in Italy and New Zealand,
this accounts for only 2 % of private cars
on the road.
Gas performs well as a fuel for cars
and trucks, while emitting roughly half
of the pollution which comes from ineffi-
cient burning of petrol (figure 2.37). In
the past systems have been developed
which allowed a driver to switch from
gas to liquid fuels at the press of a but-
ton - without stopping the car. At pre-
sent prices natural gas would cost con-
siderably less per mile than petrol.
Unfortunately retro-fitting existing mod-
els with new high-pressure storage
cylinders, new fuel lines and modified
carburettors will cost around $ 4000 for
each vehicle. Hybrid cars will also have
to find space for their gas fuel tanks,
usually in the boot, which cuts down on
storage space.
Fig. 2.36: EARLY SUBSTITUTION: The replacement of one energy resource with another has
been a recurrent theme of our history. After thousands of years of wood-burning, wood was
replaced by coal. Earlier this century coal gave way to oil as the dominant energy resource.
Now gas, with its environmental, economic and political attractions, is poised to topple oil
from its position of world dominance. Nuclear fission has been under development for the
last forty years and is just beginning to produce significant quantities of power. Despite
current excitement, fusion technology is in its infancy and unlikely to be a commercial option
until the middle of the twenty-first century.
Fig 2.37: GAS DRIVE: Gas powered
cars are not new. In future many
filling stations will provide gas as
well as diesel and petrol. The city of
Los Angeles, in the USA, is operating
a scheme to replace conventional
petrol engines with cleaner
alternatives such as hydrogen and
methanol burning engines.
0.99
0.90
0.70
0.50
0.30
0.10
0.01
Fra
ctio
n of
wor
ld to
tal c
onsu
mpt
ion
850 1900 1950 2000 2050
Nuclear Fusion
WoodCoal
Oil
Natural gas
Gas
Year
Gas-powered cars have robust fuel
cylinders which, when involved in a
road accident, are less likely to rupture
than the petrol tanks fitted to conven-
tional cars. However, this may not sat-
isfy a safety-conscious consumer. Public
perception of risk and potential benefits
will probably decide the future of nat-
ural gas as a motor fuel.
Kamal, W.A. (1993) Global Warming and the Emerging Impor-
tance of Natural Gas. SPE Paper 26175. Presented at SPE Gas
Technology Symposium, Calgary, Alberta, Canada.
Pho
to: T
ony
Sto
ne Im
ages