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

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ne Im

ages