focused energy report - gailcorintra.gail.co.in · november 9, 2012 [focused energy report] ... wti...

FOCUSED ENERGY REPORT

Monthly Report-November

Energy Desk

November 9, 2012 [FOCUSED ENERGY REPORT]

E N E R G Y D e s k

Page 1

Table of Content

A. Energy prices – Oil & NG.

B. 5 African Countries for NG prospect with their ranking.

C. Top NG Exporting countries with Proven Gas Reserves.

D. Top Crude import in India from Countries.

E. CO2 Transportation through Pipeline – an Insight.


E N E R G Y D e s k

Page 2

A. Oil & Gas (Energy) Prices in last month (September-October):

OIL ($/bbl.) /Gas ($/mmbtu)

PRICE ON 28thSeptember PRICE ON 27th October CHANGE % CHANGE

Brent crude oil 112.01 109.44 -2.57 2.29%

WTI crude oil 92.29 85.26 -7.03 -7.61%

Henry Hub Natural Gas 3.30 3.81 0.51 15.45%

Oil & Gas trend in 28th September-27thOctober 2012:

BRENT crude oil ($/barrel) WTI crude oil ($/barrel) NATURAL GAS ($/mmbtu)

B. 5 African Countries for NG prospect with ranking.

5 African countries have been selected for closer view for NG/ energy prospective from energy point of view

and a ranking has also been done for them. The countries are:

1. Algeria.

2. Mozambique

3. Tanzania

4. Egypt

5. Nigeria

A. Algeria

a. Pipeline: condensate 2,600 km; gas 16,360 km; liquid petroleum gas 3,447 km; oil 7,611 km;

refined products 144 km (2010)

b. Energy :

Electricity - production:

40.22 billion kWh (2009 est.) country comparison to the world: 58

Electricity - consumption:


Electricity - exports:

405 million kWh (2009 est.) country comparison to the world: 64

Electricity - imports:

https://www.cia.gov/library/publications/the-world-factbook/docs/notesanddefs.html#2232

https://www.cia.gov/library/publications/the-world-factbook/rankorder/2232rank.html?countryName=Algeria&countryCode=ag&regionCode=afr&rank=58#ag






http://oil-price.net/dashboard.php?lang=en




E N E R G Y D e s k

Page 3

369 million kWh (2009 est.)country comparison to the world: 79

Electricity - installed generating capacity:

10.38 million kW (2009 est.) country comparison to the world: 54

Electricity - from fossil fuels:

97.3% of total installed capacity (2009 est.) country comparison to the world: 62

Electricity - from nuclear fuels:

0% of total installed capacity (2009 est.) country comparison to the world: 37

Electricity - from hydroelectric plants:


Electricity - from other renewable sources:


Crude oil - production:

1.885 million bbl/day (2011 est.)country comparison to the world: 16

Crude oil - exports:

697,500 bbl/day (2009 est.) country comparison to the world: 20

Crude oil - imports:


Crude oil - proved reserves:

12.2 billion bbl (1 January 2012 est.) country comparison to the world: 17

Refined petroleum products - production:


Refined petroleum products - consumption:

316,400 bbl/day (2011 est.)country comparison to the world: 41

Refined petroleum products - exports:


Refined petroleum products - imports:


Natural gas - production:

84.61 billion cu m (2010 est.) country comparison to the world: 11 =231 MMSCMD

Natural gas - consumption:

28.82 billion cu m (2010 est.)country comparison to the world: 30 = 79 MMSCMD

Natural gas - exports:

55.79 billion cu m (2010 est.)country comparison to the world: 7 =152.86 MMSCMD



































E N E R G Y D e s k

Page 4

Natural gas - imports:

0 cu m (2010 est.)country comparison to the world: 151

Natural gas - proved reserves:

4.502 trillion cu m (1 January 2012 est.) country comparison to the world: 11 =123 MMSCMD with 100 Yr basis or for 50 yrs with existing production.

Carbon dioxide emissions from consumption of energy:

110.9 million Mt (2010 est.)country comparison to the world: 39

Note:

Very high Crude as well as NG production – strong case for export including India.

Energy Outlook Algeria, a closer view - Energy statistics of past: S. No

2005 2006 2007 2008 2009 2010 2011 2010-11 (%/year)

1. Total primary production (Mtoe) 166.7 165.0 164.3 162.1 152.3 151.6 148.2 -2.3

2. Total energy consumption (Mtoe) 33.0 35.4 37.5 38.0 40.5 40.4 42.7 5.9

3 Energy intensity of GDP at constant purchasing

power parities (koe/$2005p) 0.18 0.18 0.18 0.18 0.18 0.17 0.17 0.6

4 Crude oil, NGL production (Mt) 86.1 85.8 85.9 83.5 77.7 74.5 73.3 -1.6

5 Crude oil, NGL input to refineries (Mt) 18.5 18.9 19.8 22.1 23.5 25.8 25.2 -2.3

6 Refined oil products production (Mt) 26.5 26.6 28.1 30.2 30.6 33.5 32.7 -2.3

7 Oil products domestic consumption (Mt) 10.0 10.2 11.3 11.9 12.7 13.2 13.9 5.3

8 Natural gas production (bcm) 83.8 82.4 81.5 81.7 77.7 80.8 78.3 -3.0

9 Natural gas consumption (bcm) 22.8 23.9 24.8 25.0 25.9 25.9 27.7 7.0

10 Coal and lignite production (Mt) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 -

11 Coal and lignite domestic consumption

(Mt) 1.0 1.0 1.1 1.1 0.6 0.4 0.4 0.2 12 Electricity production

(TWh) 36.3 37.8 39.9 42.6 45.2 48.2 52.2 8.2 13 Electricity domestic

consumption (TWh) 29.5 29.5 31.3 32.9 34.3 36.6 39.7 8.6 14 Share of renewables in

electricity production (incl hydro) (%) 1.5 0.6 0.6 0.7 0.8 0.4 0.7 101.7

15 Share of renewables in primary consumption

(%) 0.4 0.2 0.3 0.2 0.2 0.2 0.2 13.3 16 CO2 emissions from 87.7 88.9 92.9 96.6 102.2 102.1 107.9 5.7








E N E R G Y D e s k

Page 5

fuel combustion (MtCO2)

17 CO2 intensity at constant purchasing

power parities (kCO2/$2005p) 0.33 0.34 0.34 0.34 0.35 0.36 0.38 4.4

Salient Features of Algeria’s Energy statistics

Algeria's economy is heavily reliant on its hydrocarbons sector.

Algeria is an important oil exporting country and a member of the Organization of Petroleum Exporting

Countries (OPEC).

Algeria is a significant producer and exporter of natural gas and liquefied natural gas (LNG).

Algeria's hydrocarbons sector accounted for 60% of its budget revenues, 36 % of its GDP, and over 97 % of

its export earnings in 2010, according to the U.S. State Department.

In 2010, Algeria was the fourth largest crude oil producer in Africa after Nigeria, Angola, and Libya. As a

member of OPEC, Algeria's crude oil production can be constrained by the group's crude production quotas,

but Algeria also produces condensate and natural gas liquids, which are exempt from OPEC quotas.

Algeria was the eighth largest natural gas producer in the world in 2010 and the third largest gas supplier to

Europe.

According to the Oil and Gas Journal (OGJ), Algeria held an estimated 12.2 billion barrels of proven oil

reserves as of January 2012, the third largest reserves in Africa (behind Libya and Nigeria). Hassi Messaoud

basin, located in the eastern part of the country near the Libyan border, is the country's largest oil basin and

producing oilfield and contains up to 60 percent of Algeria's proven oil reserves. The Berkine basin, together

with the Ourhoud fields, is the second largest in the country and has been the source of a number of recent

discoveries, which have allowed Algerian oil production levels to rise significantly since 2003.

Organization :

The Algerian national oil company is Entreprise Nationale Sonatrach (Sonatrach), which plays a key role in

all aspects of the oil and natural gas sectors in Algeria. All foreign operators must work in partnership with

Sonatrach, which usually has majority ownership in production-sharing agreements.

Since the late 1990s, Algeria has encouraged the expansion of foreign investment in the oil and gas sectors.

Foreign oil operators have steadily increased their participation in exploration and production, which has led

to reserve and production growth. The largest foreign oil producer is Anadarko, with total production capacity

of more than 500,000 bbl/d from its operation at the combined Hassi Berkine South and Ourhoud fields. Other

large foreign investors include: BP, Conoco-Phillips, Eni, Shell, Statoil, and Total.

Production and Development:

Algeria produced an estimated average of 1.27 million barrels per day (bbl/d) of crude oil in 2011, about the

same as it produced in 2010. Together with 270,000 bbl/d of condensate and 340,000 bbl/d of natural gas

liquids, which are not included in its OPEC quota, Algeria averaged 1.88 Mmbbl/d of total oil liquids

production during 2011.

Algerian oilfields produce high quality light crude oil with very low sulfur and mineral contents. The main

areas for exploration are in the east near the borders of Tunisia and Libya, and in the central area, where large

natural gas discoveries have been made. Algeria is maintaining its oil production capacity by enhancing oil

recovery in older fields, increasing exploration, and developing new oilfields to compensate for the decline in

older fields. The government's long-term target is to maintain crude oil production capacity at about its current

level.


E N E R G Y D e s k

Page 6

Exports:

In 2011, Algeria's estimated crude oil exports were 750,000 bbl/d, of which the largest portion went to North

America, mainly to the United States. In 2010, Algeria's estimated total oil exports (including all liquids) were

1.5 million bbl/d. According to EIA estimates, the United States imported an average of 510,000 bbl/d from

Algeria in 2010, of which 328,000 bbl/d was crude oil. The United States was the largest single importer of

Algerian crude oil in both years.

Downstream:

In January 2012, Algeria had total crude oil refining capacity of 450,000 bbl/d at four refineries, according to

the Oil and Gas Journal.

Pipelines and Export Terminals:

Algeria uses seven coastal terminals to export crude oil, refined products, LPG, and natural gas liquids (NGL).

These facilities are located at Arzew, Skikda, Algiers, Annaba, Oran, Bejaia, and La Skhirra in Tunisia.

Arzew handles about 40 percent of Algeria's total hydrocarbon exports, including all of its NGL, LPG, and oil

condensate exports. Arzew and Skikda are also the shipping points for LNG.

Algeria's domestic pipeline network facilitates the transfer of oil from interior production fields to the export

terminals. Sonatrach operates over 2,400 miles of oil pipelines in the country. The most important pipelines

carry crude oil from the Hassi Messaoud field to refineries and export terminals. Algeria's major crude oil

export pipelines are: the two parallel 500-mile Haoud el Hamra to Arzew pipelines, the 415-mile Haoud el

Hamra to Bejaia line, the 400-mile Haoud el Hamra to Skikda pipeline, and the border-crossing 482-mile

pipeline from In Amenas to La Skhirra, Tunisia. Sonatrach also operates oil condensate and LPG pipeline

networks that link Hassi R'Mel and other fields to Arzew.

Natural Gas:

According to The Oil and Gas Journal (OGJ), as of January 2012, Algeria had 159 trillion cubic feet (Tcf) of

proven natural gas reserves, the tenth largest natural gas reserves in the world and the second largest in Africa

after Nigeria. Algeria's largest natural gas field is Hassi R'Mel, discovered in 1956. Located in the eastern

part of the country, it holds proven reserves of about 85 Tcf, more than half of Algeria's total proven natural

gas reserves. The remainder of Algeria's natural gas reserves come from associated (they occur alongside

crude oil reserves) and non-associated fields in the south and southeast regions of the country.

Production:

Algeria's gross natural gas production in 2010 was 6.8 Tcf compared with 6.9 Tcf in 2009. Of this amount, 3.2

Tcf was reinjected for enhanced oil recovery, 3.5 Tcf was marketed, while 0.2 Tcf was vented/flared.

Algeria is in the process of developing its Southwest Gas Project, which includes the Repsol-led 102 billion

cubic feet per year (Bcf/y) Reggane Nord fields, the 56 Bcf/y Timimoun project led by Total, and GDF Suez's

159 Bcf/y Touat project. Final approval of the Reggane Nord project occurred in November 2011. The project

includes the construction of gas gathering facilities, a gas treatment plant, and pipeline to Hassi R'Mel gas

hub. Repsol holds a 29.25 percent stake in partnership with Sonatrach, at 40 percent, RWE Dea, at 19.5

percent, and Edison, at 11.25 percent. The project is slated to come online in mid-2016, 2 years later than

originally estimated. Reggane Nord will open up the wider development of Algeria's southwest gas fields,

including the Timimoun and Touat projects. The Timimoun project is projected to come onstream in 2014,

and the Touat project is also expected to be given the green light soon, according to Algeria's state news

agency in February 2012.

Another major project in the area, the Menzel Ledjmet East (MLE) project led by Eni, is projected to start

production of 116 Bcf/y in mid-2012, along with associated gas liquids and oil. The projects in the southwest

are co-dependent, as they will all rely on the construction of a new gas pipeline linking them to Hassi R'Mel.

Following a recent decline in upstream licensing activity, the development of gas from the southwest has

taken on greater importance for Algeria's capacity to meet contracted gas exports and increasing domestic

demand in the medium term.


E N E R G Y D e s k

Page 7

Pipeline Exports:

According to Cedigaz estimates, Algeria's natural gas exports totaled 1.97 Tcf in 2010, up from 1.86 Tcf in

2009. About 65 percent of Algeria's total natural gas exports, or 1.29 Tcf, moved through the natural gas

pipelines connecting Algeria with Italy and Spain, while 35 percent, or 0.682 Tcf, was exported by tanker in

the form of LNG. Algeria was the third largest natural gas supplier to Europe after Russia and Norway in

2010.

After a number of delays, the $1.2 billion Medgaz undersea pipeline came online in March, 2011. The 403

Bcf/y-capacity, 120-mile Medgaz undersea line links Beni Saf, Algeria to Almeria, Spain. Sonatrach owns 36

percent, Spain's Iberdrola and Cepsa each own 20 percent, and Endesa and Gaz de France hold 12 percent

each. Interconnecting pipelines from Spain to France, which would make France and the rest of Europe

potential outlets for Spain's surplus gas, are in the planning stages, and could become operational in the 2013-

2015 time frame.

The 1,370-mile Trans-Mediterranean (Transmed, also called Enrico Mattei) line runs from Hassi R'Mel, via

Tunisia and Sicily, to mainland Italy, with an extension running to Slovenia. It was completed in 1983 and

doubled in capacity in 1994 to 847 Bcf/y. A third line was opened in February 2010, further expanding total

capacity to 1,059 Bcf/y.

The 1,000-mile, 424 Bcf/y capacity Maghreb-Europe Gas pipeline (MEG, also called Pedro Duran Farell),

was completed in 1996 for $2.3 billion. It connects Hassi R'Mel via Morocco with Cordoba, Spain, where it

ties into the Spanish and Portuguese natural gas transmission networks. Natural gas from Algeria is provided

to Spain, Portugal, and Morocco. An international consortium, led by Spain's Enagas, Morocco's SNPP,

Portugal's Transgas and Sonatrach, operates this line.

The Galsi natural gas pipeline, which would link Annaba on the Algerian coast with Piombino in mainland

Italy via Sardinia, is still in the planning stages. It would be the deepest underwater pipeline ever built,

running 9,265 feet underwater at its deepest point. The expected initial capacity is 282 Bcf/year and it has

been projected to come on stream in 2014.

Liquefied Natural Gas:

In 2010, Algeria was the world's seventh largest exporter of LNG, exporting about 7 percent of the world's

total LNG exports. Primary customers were France, Spain, Turkey, Italy, and the U.K. Cedigaz estimates that

a total of 682 Bcf of LNG was exported in 2010, comprising 35 percent of the country's total natural gas

exports.

With the start-up of the LNG plant at Arzew in 1964, Algeria became the world's first producer of LNG. The

Arzew plant had three trains until February 2011, when the oldest was closed down, being considered too

dilapidated and dangerous to operate. This deprived Algeria of around 53 Bcf/y of LNG. A new LNG plant

with capacity of 218 Bcf/y is under construction and due to open in 2013. Gas supplies will be coming from

the Gassi Touil fields.

Algeria’s Skikda LNG plant, built in 1972, was partly destroyed by an explosion in 2004. Three of the six

trains were repaired but the other three are being replaced by one new train with a 250 Bcf/y capacity,

expected to come online in 2013.

The National Shipping Company, a Sonatrach subsidiary, operates 28 LNG, crude, and product tankers and

has reportedly commissioned a further 10 vessels for delivery by 2013.

B. Mozambique:

a. Pipeline:

Natural Gas 918 km; refined products 278 km (2010)

b. Energy:


E N E R G Y D e s k

Page 8

Electricity Production :





12.94 billion kWh (2009 est.)country comparison to the world: 14








0% of total installed capacity (2009 est.)country comparison to the world: 146






0 bbl/day (2011 est.) country comparison to the world: 170






0 bbl (1 January 2012 est.) country comparison to the world: 169








https://www.cia.gov/library/publications/the-world-factbook/rankorder/2232rank.html?countryName=Mozambique&countryCode=mz&regionCode=afr&rank=78#mz

































E N E R G Y D e s k

Page 9

Note :

Due to less consumption in country, Export is possible with some NG reserve as on date.

C. Tanzania:

a. Pipeline :

Natural gas 254 km; oil 888 km; refined products 8 km (2010)

b. Energy :



3.12 billion cu m (2010 est.) country comparison to the world: 54 = 8.5 MMSCMD


80 million cu m (2010 est.) country comparison to the world: 109 = 0.219 MMSCMD


3.04 billion cu m (2010 est.) country comparison to the world: 36 8.3 MMSCMD


0 cu m (2010 est.) country comparison to the world: 103


127.4 billion cu m (1 January 2012 est.) country comparison to the world: 52 =3.47 MMSCMD for 100 yrs and 40 yrs reserves with existing production of 8.5 MMSCMD


2.728 million Mt (2010 est.)

Electricity- production:





0 kWh (2010 est.)country comparison to the world: 142




957,000 kW (2009 est.) country comparison to the world: 124


















https://www.cia.gov/library/publications/the-world-factbook/rankorder/2233rank.html?countryName=Tanzania&countryCode=tz&regionCode=afr&rank=126#tz












E N E R G Y D e s k

Page 10

Note : Gas reserves in Tanzania as of today is very less.


60.5% of total installed capacity (2009 est.)country comparison to the world: 31




0 bbl/day (2011 est.)country comparison to the world: 197






0 bbl (1 January 2012 est.)country comparison to the world: 197










780 million cu m (2010 est.) country comparison to the world: 67=2 MMSCMD


780 million cu m (2010 est.)country comparison to the world: 93 =2 MMSCMD






6.513 billion cu m (1 January 2012 est.)country comparison to the world: 85 = 2 MMSCMD for 10 yrs



































E N E R G Y D e s k

Page 11

D. Egypt

a. Pipeline:

condensate 320 km; condensate/gas 13 km; gas 6,628 km; liquid petroleum gas 956 km; oil

4,332 km; oil/gas/water 3 km; refined products 895 km; water 13 km (2010)

b. Energy:

Electricity production :







183 million kWh (2009 est.)country comparison to the world: 87


















4.4 billion bbl (1 January 2012 est.) country comparison to the world: 29








https://www.cia.gov/library/publications/the-world-factbook/rankorder/2232rank.html?countryName=Egypt&countryCode=eg&regionCode=afr&rank=28#eg

































E N E R G Y D e s k

Page 12

Remarks:

Reserve Potential is there for 50 Yrs. with some export provision.

Energy outlook –Egypt, a closer view - Energy statistics of past:

S. No 2005 2006 2007 2008 2009 2010 2011

2010-11 (%/year)

1. Total primary production (Mtoe) 77.2 80.0 82.6 87.8 88.5 87.9 87.6 -0.3

2. Total energy consumption (Mtoe) 61.1 64.1 67.5 71.0 72.2 75.4 78.6 4.2

3 Energy intensity of GDP at constant purchasing power

parities (koe/$2005p) 0.18 0.18 0.18 0.17 0.17 0.17 0.17 2.4 4 Crude oil, NGL production

(Mt) 32.2 32.0 32.9 34.9 33.4 34.0 33.7 -0.9 5 Crude oil, NGL input to

refineries (Mt) 31.5 31.4 32.5 30.8 29.8 32.6 32.1 -1.8 6 Refined oil products

production (Mt) 32.3 32.1 33.8 32.1 30.4 33.3 32.7 -1.8 7 Oil products domestic

consumption (Mt) 28.4 29.4 31.2 31.1 30.7 32.3 32.2 -0.4 8 Natural gas production

(bcm) 50.9 54.6 56.2 60.2 63.0 61.7 61.6 -0.1 9 Natural gas consumption

(bcm) 35.4 38.0 39.6 42.5 43.9 45.8 50.6 10.6 10 Coal and lignite production

(Mt) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 11 Coal and lignite domestic

consumption (Mt) 1.4 1.4 1.4 1.3 1.3 1.4 1.5 5.1 12 Electricity production

(TWh) 108.7 115.4 125.1 131.0 139.0 146.8 152.1 3.6 13 Electricity domestic

consumption (TWh) 92.1 98.4 106.6 111.7 118.9 125.2 127.8 2.1



61.33 billion cu m (2010 est.) country comparison to the world: 15 =168 MMSMCMD


46.16 billion cu m (2010 est.)country comparison to the world: 18 =126 MMSCMD


15.17 billion cu m (2010 est.) country comparison to the world: 18 = 41.5 MMSCMD


0 cu m (2010 est.) country comparison to the world: 189


2.186 trillion cu m (1 January 2012 est.) country comparison to the world: 17= 60 MMCMD 100 Yrs basis

















E N E R G Y D e s k

Page 13

14 Share of renewables in electricity production (incl

hydro) (%) 12.1 11.7 13.1 11.9 10.1 10.0 10.2 2.0 15 Share of renewables in

primary consumption (%) 4.2 4.1 4.3 4.1 3.8 3.8 3.8 -0.7 16 CO2 emissions from fuel

combustion (MtCO2) 150.5 159.1 166.2 172.0 175.1 183.1 189.9 3.8 17 CO2 intensity at constant

purchasing power parities (kCO2/$2005p) 0.45 0.44 0.43 0.42 0.40 0.40 0.41 2.2

Salient Features of Egypt’s Energy statistics

Egypt is a significant oil producer and a rapidly growing natural gas producer. The Suez Canal

and Sumed Pipeline are strategic routes for Persian Gulf oil shipments, making Egypt an

important transit corridor for world energy markets.

Egypt is now reliant upon oil imports to meet domestic energy demand.

Due to major recent discoveries, natural gas is likely to be the primary growth engine of Egypt's

energy sector for the foreseeable future.

Closure of the Suez Canal and SUMED Pipeline would add an estimated 6,000 miles of transit

around the continent of Africa.

Egypt's installed generating capacity stood at 23.4 gigawatts (GW) as of 2008, with plans to

further expand capacity through additional investments in natural gas, nuclear and renewable

energy.

Egypt is the largest oil producer in Africa that is not a member of the Organization of Petroleum

Exporting Countries (OPEC), and the second largest natural gas producer on the continent, following

Algeria. Egypt also plays a vital role in international energy markets through the operation of the Suez

Canal and Suez-Mediterranean (SUMED) Pipeline, important transit points for oil and liquefied natural

gas (LNG) shipments from African and Persian Gulf states to Europe and the Mediterranean Basin. Fees

collected from operation of these two transit points are significant sources of revenue for the Egyptian

government.

Total Primary Energy Consumption

Almost all of Egypt's 3.4 quadrillion British thermal units (Btu) of energy consumption in 2009 was met

by oil (47 percent) and natural gas (48 percent)

Oil

According to the Oil and Gas Journal's January 2012 estimate, Egypt's proven oil reserves are 4.4 billion

barrels, an increase from 2010 reserve estimates of 3.7 billion barrels. New discoveries have boosted oil

reserves in recent years. In 2011, Egypt's total oil production averaged around 710,000 bbl/d, of which

approximately 560,000 bbl/d was crude oil including lease condensates and the remainder natural gas

liquids (NGLs).


E N E R G Y D e s k

Page 14

Egypt's oil consumption has outpaced production since 2008. Accordingly, as consumption increased,

Egypt's imports of both crude oil and refined petroleum products increased to make up for decreased oil

output. Although Egypt has the largest oil refining sector in Africa, a small volume of refined petroleum

product imports are used to meet domestic demand.

Exploration and Production

Egyptian oil production comes from five main areas: primarily the Gulf of Suez and the Nile Delta, and

also the Western Desert, the Eastern Desert, and the Mediterranean Sea. Most Egyptian production is

derived from mature, relatively small fields that are connected to larger regional production systems.

Overall production is in decline, particularly from the older fields in the Gulf of Suez. However, some

declines have been offset by small yet commercially viable discoveries in all producing areas, in addition

to EOR techniques used in mature fields.

As a result of extensive exploration, new discoveries, and EOR techniques used to extract more oil from

mature fields, Egypt's oil production increased slightly in 2009. New finds in the Mediterranean

deepwater offshore and in mature productive areas in the Gulf of Suez and Nile Delta may offer the

country sustained oil resources in the future. Additionally, exploration is ongoing in the onshore Western

Desert area, where oil discoveries are generally cheaper to exploit. Since 2000, oil output in the Western

Desert area has doubled, and it now accounts for around 28 to 30 percent of total oil production,

according to IHS Cera.

Crude oil Exports by destination:

Crude Oil export by destination:

In 2011, just over half of Egyptian oil exports were sent to India (60,000 bbl/d), followed by Italy (25,000

bbl/d). India and Italy are traditionally top destinations for Egypt's crude oil exports. The remainder of


E N E R G Y D e s k

Page 15

Egypt's crude exports went to other European and Asian countries in 2011, as with previous years. The

U.S. has traditionally imported small volumes of crude oil and petroleum products from Egypt, although

according to EIA estimates, volumes were reduced last year.

Natural Gas

Egypt's natural gas sector has been expanding rapidly, as production has more than tripled from 646

Billion cubic feet (Bcf) in 2000 to 2.2 Tcf in 2010. According to OG Jestimates from January 2012,

Egypt's proven gas reserves registered at 77 Tcf, an increase from 2010 estimates of 58.5 Tcf and the

third highest in Africa, after Nigeria and Algeria. New discoveries offshore the Nile Delta and some finds

in the Western Desert have led to the increase in proven reserves. Over 80 percent of Egypt's natural gas

reserves and 70 percent of its production is located in the Mediterranean and Nile Delta.

In 2010, Egypt produced roughly 2.2 Tcf and consumed just over 1.6 Tcf of dry natural gas. Gas

production is expected to continue to grow to satisfy rising domestic demand, export commitments

through the Arab Gas Pipeline, and LNG exports. Thus, Egypt is expected to continue to be an important

natural gas supplier to Europe and the Mediterranean region, although exports are competing with rising

domestic demand, particularly in Egypt's power generation sector.

In 2009, the electricity sector accounted for the largest share of natural gas consumption (54 percent)

followed by the industrial sector (29 percent), according to Cedigaz. The government is also encouraging

households, businesses and the industrial sector to consider natural gas as a substitute for petroleum and

coal. In January 2008, the World Bank approved loans for the Natural Gas Connections Project, which

serves to switch consumption of liquefied petroleum gas (LPG) to natural gas through investment in new

connections and to further expand natural gas use in densely populated, low income areas.

The share of natural gas consumed in the transportation sector has also been rising since the development

of compressed natural gas (CNG) infrastructure and vehicles. According to the Ministry of Petroleum in

Egypt, the quantity of natural gas vehicles sold in Egypt between the fiscal years 2004/2005 and

2009/2010 more than doubled.

Sector Organization

As is the case with the oil sector, the Egyptian General Petroleum Corporation (EGPC) is the state entity

charged with managing upstream activities including infrastructure, licensing and production. Egyptian

Natural Gas Holding Company (GASCO) is charged with promoting the sector, establishing a


E N E R G Y D e s k

Page 16

development strategy, and distributing tenders. According to a recent government announcement,

GASCO will be offering tenders to international companies this year for on- and offshore natural gas

blocks near Egypt's maritime border with Israel.

The Egyptian government has an ongoing policy to allocate one-third of proven natural gas reserves for

domestic market requirements, one-third for future generations, and the remaining third for exports.

Given increasing domestic demand, combined with popular pressures in recent years against LNG and

gas export contracts (particularly with Israel), the oil minister declared in mid-2008 that no new gas

export contracts would be made. These policies delayed plans to expand the export infrastructure and

have also deterred some investment in the more expensive offshore areas.

Foreign companies operating in Egypt's gas sector must direct all or a portion of its current production to

the domestic market, while new discoveries are earmarked for domestic market. Major foreign players

include Eni, BG Group, BP, and Apache. BG Group produces about 40 percent of Egypt's total gas

production, which amounted to 794 Million cubic feet per day (Mcf/d) in 2011 and was mainly derived

from the offshore Nile Delta, according to IHS Cera. The vast majority of BG's output is used to supply

the domestic market.

BP produced about 444 Mcf/d of gas in 2011, but is planning to increase output through its recent

discoveries in the Gulf of Suez and Mediterranean. The company was also the first to secure an

agreement with the government for higher gas prices for production from its deepwater areas, according

to IHS Cera. Eni is another major player in Egypt's gas industry, and operates fields mainly in the

Mediterranean and Nile Delta areas through its JV and subsidiary.

Exploration and Production

Exploration and production activities in the country's natural gas sector continue to grow. While there

have been marked decreases in the production of natural gas associated with oil extraction, new finds of

non-associated gas fields, combined with growing domestic demand and export capacity, are increasing

interest in Egypt's natural gas sector. Exploration has occurred in the offshore Mediterranean, onshore

Nile Delta, and in the Western Desert. However, between 2006 and 2010, there was a slowdown in

deepwater exploration. To promote foreign participation in the exploration of the more expensive

deepwater offshore, the Egyptian government revised pricing policies by agreeing to pay more for natural

gas produced in these areas.

Most industry analysts place Egypt's natural gas production on an upward trend in the short- and medium-

term, despite the existing limitations to the sector's growth. Current production mostly occurs in the Nile

Delta area and surrounding offshore areas, with the Abu Madi, Badreddin and Abu Qir non-associated

fields in the Delta accounting for about half of Egypt's total gas production. Most recent finds have been

in the deepwater Mediterranean, which are being exploited by industry giants such as Shell, BG, and Eni.

Exports

Dry natural gas exports, which began in 2003, had been rising rapidly, with the completion of the Arab

Gas Pipeline (AGP) in 2004 and the startup of the first three LNG trains at Damietta in 2005. However,

after 2006 exports began to level off and in 2010, natural gas exports fell to 535 Bcf, an almost 20

percent drop from the prior year. According to the country's petroleum minister, low international prices

and growing domestic demand led to the government's decision to enact a two-year moratorium on new

gas export deals at the end of 2008 in response to increased electricity consumption at gas fired power

plants. Around 70 percent of total natural gas exports are in the form of LNG, and the remaining 30

percent are exported via pipelines.

Pipeline Exports

The Arab Gas Pipeline (AGP) originates in Egypt and provides gas to Jordan, Syria, and Lebanon, with

recent additions extending the pipeline to Turkey and European markets. In 2008, the pipeline was

extended at its starting point in al-Arish in Egypt to Ashkelon in Israel. However, AGP has been


E N E R G Y D e s k

Page 17

sabotaged on over a dozen occasions between 2011 and 2012 due to political protest, which has resulted

in gas supply disruptions to recipient countries.

Israel and Jordan have been most affected from supply cut-offs since they are most dependent on Egyptian

gas. Prior to the attacks, about 40 percent of Israel's gas consumption and 80 percent of Jordan's power

generation derived from Egypt's gas supply, according to IHS Cera. As a result of the pipeline attacks, gas

supplied by Egypt to Jordan dropped by 60 percent from 2010 to 2011. In late-April 2012, Egyptian state-

owned oil and gas companies announced that they were terminating their agreement to supply gas to

Israel under the premise that Israel did not meet payment deadlines in recent months. Although gas

supplies to Israel had become a contentious political topic in Egypt over the years.

Liquefied Natural Gas (LNG)

Egypt has three LNG trains: Segas LNG Train 1 in Damietta and Egypt LNG trains 1 and 2 in Idku. The

combined LNG export capacity is close to 600 Bcf per year with plans to expand in the near future,

pending export policy changes and legislation. In 2010, as domestic demand for natural gas increased,

LNG exports fell to about 354 Bcf, which was down by 30 percent from almost 500 Bcf in 2009.

In 2010 half of Egypt's LNG was shipped to Europe, which imported about 180 Bcf, with over half of that

destined for Spain (110 Bcf). The US was the second largest recipient of Egyptian LNG in 2010, and

imported just over 71 Bcf. Other major destinations included Korea (36 Bcf), Japan (21 Bcf), and Chile

(18 Bcf).

E. Nigeria

a. Pipelines :

condensate 26 km; gas 2,756 km; liquid petroleum gas 97 km; oil 3,441 km; refined

products 4,090 km (2010)

b. Energy:


E N E R G Y D e s k

Page 18

Electricity Production :









5.898 million kW (2009 est.)country comparison to the world: 69
















37.2 billion bbl (1 January 2012 est.)country comparison to the world: 11








https://www.cia.gov/library/publications/the-world-factbook/rankorder/2232rank.html?countryName=Nigeria&countryCode=ni&regionCode=afr&rank=73#ni

































E N E R G Y D e s k

Page 19

Note: Strong case of export to countries including India.

Energy outlook Nigeria, a closer view - Energy statistics of past:

S. No 2005 2006 2007 2008 2009 2010 2011 2010-11 (%/year)

1. Total primary production (Mtoe) 233.2 234.9 231.3 228.2 228.6 256.0 255.9 0.0

2. Total energy consumption

(Mtoe) 104.1 105.1 105.8 110.8 108.1 110.8 113.3 2.2 3 Energy intensity of

GDP at constant purchasing power

parities (koe/$2005p) 0.43 0.40 0.38 0.38 0.35 0.33 0.31 -4.9

4 Crude oil, NGL production (Mt) 128.0 122.9 114.1 109.7 115.1 132.2 127.7 -3.3

5 Crude oil, NGL input to refineries (Mt) 9.7 6.0 2.7 5.5 2.5 5.0 5.6 13.0

6 Refined oil products production (Mt) 9.6 5.8 2.8 5.0 2.4 4.7 5.3 13.0

7 Oil products domestic

consumption (Mt) 11.1 9.3 8.4 10.3 9.4 8.7 8.3 -3.9 8 Natural gas

production (bcm) 22.4 28.5 32.5 31.7 23.2 32.9 35.7 8.6 9 Natural gas

consumption (bcm) 9.8 10.9 10.8 11.2 7.2 8.9 9.7 9.7 10 Coal and lignite

production (Mt) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.2



29 billion cu m (2010 est.)country comparison to the world: 29 = 79 MMSCMD


4.97 billion cu m (2010 est.)country comparison to the world: 60 = 13.6 MMSCMD


24.02 billion cu m (2010 est.)country comparison to the world: 14 = 65 MMSCMD




5.11 trillion cu m (1 January 2012 est.)country comparison to the world: 10 =140 MMSMD 100 yrs basis
















E N E R G Y D e s k

Page 20

11 Coal and lignite domestic

consumption (Mt) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.2 12 Electricity

production (TWh) 23.5 23.1 23.0 21.1 19.8 22.8 24.8 8.9 13 Electricity domestic

consumption (TWh) 17.3 15.3 19.7 18.5 18.1 20.8 22.7 8.9 14 Share of renewables

in electricity production (incl

hydro) (%) 33.0 27.1 27.1 27.1 22.9 19.4 20.1 3.8 15 Share of renewables

in primary consumption (%) 81.0 82.1 83.5 81.6 85.4 85.1 85.1 0.0

16 CO2 emissions from fuel combustion

(MtCO2) 53.0 49.2 45.7 54.1 42.5 43.7 44.4 1.5 17 CO2 intensity at

constant purchasing power parities

(kCO2/$2005p) 0.20 0.18 0.16 0.17 0.13 0.12 0.12 -5.7

Salient Features of Nigeria’s Energy statistics

Nigeria's hydrocarbon resources are the mainstay of the country's economy, but development

of the oil and natural gas sectors is often constrained by instability in the Niger Delta.

For the last nine years, the U.S. has imported between 9-11 percent of its crude oil from

Nigeria; however, U.S. import data for the first half of 2012 show that Nigerian crude is down

to a 5 percent share of total U.S. crude imports.

Nigerian LNG exports to the U.S. substantially declined in 2011, while the country's LNG

exports to Japan more than triple

Nigeria is the largest oil producer in Africa and has been a member of the Organization of Petroleum

Exporting Countries (OPEC) since 1971. In 2011, Nigeria produced about 2.53 million barrels per day

(bbl/d) of total liquids, well below its oil production capacity of over 3 million bbl/d, due to production

disruptions that have compromised portions of the country's oil for years.

The oil industry is primarily located in the Niger Delta where it has been a source of conflict. Local

groups seeking a share of the oil wealth often attack the oil infrastructure and staff, forcing companies to

declare force majeure on oil shipments. At the same time, oil theft, commonly referred to as

"bunkering," leads to pipeline damage that is often severe, causing loss of production, pollution, and

forcing companies to shut-in production. Protest from local groups over environmental damages from

oil spills and flaring undermined relations between local communities and international oil companies

(IOCs). The industry has been blamed for pollution that has damaged air, soil, and water, leading to

losses in arable land and decreasing fish stocks.

In addition to oil, Nigeria holds the largest natural gas reserves in Africa, but has limited infrastructure

in place to develop the sector. Natural gas that is associated with oil production is mostly flared, but the

development of regional pipelines, the expansion of liquefied natural gas (LNG) infrastructure, and

policies to ban gas flaring are expected to accelerate growth in the sector, both for export and domestic

use in electricity generation. Uncertainties in Nigeria's investment policies and regulatory framework

have caused a slowdown in oil and gas exploration activity, and delays in project development,


E N E R G Y D e s k

Page 21

including LNG projects. However, the long-awaited and delayed Petroleum Industry Bill (PIB) could

potentially iron out investment uncertainties and set a regulatory framework for the country's oil and gas

industry.

Nigeria has vast natural gas, coal, and renewable energy resources that could be used for domestic

electricity generation. However, the country lacks policies to harness resources and develop new (and

improve current) electricity infrastructure. The Nigerian government has had several plans to address

the need for power, including a recent announcement to create 40 gigawatts (GW) of capacity by 2020

(compared to 2009 installed capacity of 6 GW). Achieving this goal will mainly depend on the ability of

the Nigerian government to utilize currently flared natural gas.

According to Oil and Gas Journal (OGJ), Nigeria has an estimated 37.2 billion barrels of proven oil

reserves as of the end of 2011. The majority of reserves are found along the country's Niger River Delta

and offshore in the Bight of Benin, the Gulf of Guinea, and the Bight of Bonny. Current exploration

activities are mostly focused in the deep and ultra-deep offshore with some activities in the Chad basin,

located in the northeast of the country.

The government hopes to increase proven oil reserves to 40 billion barrels in the next few years;

however, exploration activity levels are at their lowest in a decade and only three exploratory wells

were drilled in 2011, compared to over 20 in 2005. Rising security problems related to oil theft, pipeline

sabotage, and piracy in the Gulf of Guinea, coupled with investment uncertainties surrounding the long-

delayed PIB, have curtailed oil exploration projects and impeded the country from reaching its ongoing

target to increase production to 4 million bbl/d. Instead, crude oil production averaged 2.13 million

bbl/d in 2011, roughly the same as it was a decade ago, and total liquids production averaged 2.53

million that same year, which is still below the peak production of 2.63 million bbl/d reached in 2005.

Production :

In 2011, crude oil production averaged close to 2.13 million bbl/d, up from 2.05 million bbl/d in the

previous year. EIA's recent estimates show that crude output rose slightly again in 2012 and averaged

almost 2.15 million bbl/d for the first half of this year. The recent increase in production is due to the

expansion of existing fields and new production from deepwater fields. The latest major deepwater field

to come onstream was Total's Usan field, which began producing over 100,000 bbl/d in July 2012 and is

expected to reach 180,000 bbl/d by the end of this year.

Oil production in Nigeria reached its peak of 2.63 million bbl/d in 2005, but began to decline

significantly as violence from militant groups surged, forcing many companies to withdraw staff and

shut in production. The lack of transparency of oil revenues, tensions over revenue distribution, and

environmental damages from oil spills, coupled with local ethnic and religious tensions have created a

fragile situation in the oil-rich Niger Delta basin. As a result, crude oil production plummeted by more

than 25 percent by 2009, four years after reaching its peak.

http://www.eia.gov/countries/analysisbriefs/Nigeria/images/nigeria_map.png

http://www.eia.gov/countries/analysisbriefs/Nigeria/images/energy_consumption.png


E N E R G Y D e s k

Page 22

Security risks

Since December 2005, Nigeria has experienced increased pipeline vandalism, kidnappings, and militant

takeovers of oil facilities in the Niger Delta. The Movement for the Emancipation of the Niger Delta

(MEND) is the main group attacking oil infrastructure for political objectives, claiming to seek a

redistribution of oil wealth and greater local control of the sector. Additionally, kidnappings of oil

workers for ransom are common and security concerns have led some oil services firms to pull out of

the country and oil workers unions to threaten strikes over security issues. The instability in the Niger

Delta has also caused significant amounts of shut-in production at onshore and shallow offshore fields,

and forced several companies to declare force majeure on oil shipments.

The amnesty program implemented in 2009 led to decreased attacks in 2009-2010 and some companies

were able to repair damaged oil infrastructure. However, the lack of progress in job creation and

economic development has led to increased bunkering and other attacks in 2011.

Bunkering, which in the context of Nigeria's oil industry refers to the theft and trade of stolen oil, has

recently surged, and according to NNPC data, pipeline vandalism increased by 224 percent in 2011 over

the previous year. Estimates from Nigeria's Ministry of Finance show that about 400,000 bbl/d of oil

was stolen in April 2012, which led to a fall of about 17 percent in official oil sales. Royal Dutch Shell,

Nigeria's largest producer, recently estimated that 150,000-180,000 bbl/d, or 6 percent of the country's

total production, on average is lost to oil bunkering and spills.

According to information disseminated by an investigative task force in Nigeria, there are three main

ways oil is bunkered: by small cargo canoes that navigate the swampy, shallow waters of the Niger

Delta where culprits puncture pipelines to siphon crude into small tanks; stealing crude directly from the

wellhead; or filling tankers at export terminals, which is referred to as "white collar" bunkering. Some

stolen oil is taken to illegal refineries along the Niger Delta's swampy bush areas and sold domestically

and regionally, while other portions make their way to the international market. Some analysts believe

that white collar bunkering is not included in Shell's oil theft estimate and that the average amount

stolen is actually closer to the Finance Ministry's estimate, although there is no official number.

In addition to losses in official oil sales, oil theft and illegal refineries are causing environmental

damages and costing the country $7 billion a year, according to the Nigerian government. According to

the Nigerian National Oil Spill Detection and Response Agency (NOSDRA) approximately 2,400 oil

spills had been reported between 2006 and 2010 that resulted from sabotage, bunkering, and poor

infrastructure. The amount of oil spilled in Nigeria has been estimated to be around 260,000 barrels per

year for the past 50 years, according to a report cited in the New York Times.

The oil spills have caused land, air, and water pollution and severely affected surrounding villages by

decreasing fish stocks and contaminating water supplies and arable land. The United Nations

Environment Program (UNEP) released a study on Ogoniland and the extent of environmental damage

from over 50 years of oil production in the region. The study confirmed community concerns regarding

oil contamination across land and water resources, stating that that the damage is ongoing and

estimating that it could take 25 to 30 years to repair.

Incidents of piracy in the Gulf of Guinea have posed a risk to deepwater offshore operations. According

to the International Maritime Organization (IMO), there were 53 piracy related attacks in the Gulf of

Guinea in 2011, up from the 47 in 2010. The attacks typically involve stolen cargo, especially crude oil,

and violence against crew members. The country's deepwater offshore production has been relatively

unharmed by the country's instability, as oil platforms are miles out from the coast, but piracy does pose

a security risk to deepwater offshore production. Although incidences of Nigerian piracy are still less

than in Somalia, Nigerian piracy is becoming more frequent and happening at greater distances away

from the coast, according to IMO.

http://nosdra.gov.ng/

http://www.nytimes.com/2010/06/17/world/africa/17nigeria.html

http://www.unep.org/newscentre/Default.aspx?DocumentID=2649&ArticleID=8827

http://www.icc-ccs.org/piracy-reporting-centre/imb-live-piracy-map


E N E R G Y D e s k

Page 23

International oil companies:

Foreign companies operating in joint ventures (JVs) or production sharing contracts (PSCs) with the

NNPC include ExxonMobil, Chevron, Total, Eni, Addax Petroleum (recently acquired by Sinopec of

China), ConocoPhillips, Petrobras, StatoilHydro, and others.

Shell has been working in Nigeria since 1936, and currently operates the largest nameplate crude oil

production capacity, estimated to be between 1.2-1.3 million bbl/d. However, the company has been

hardest hit by the instability as much of its production is in shallow water and onshore the Niger Delta.

Much of Shell's crude oil production capacity is shut-in, some since as far back as early 2006.

According to Shell, the total oil produced from Shell-run operations averaged 974,000 bbl/d in 2011.

Shell operates in Nigeria through the Shell Petroleum Development Company of Nigeria Limited

(SPDC) and the Shell Nigeria Exploration and Production Company Limited (SNEPCo). SPDC is the

largest oil and gas company in Nigeria and is a joint venture between NNPC (55%), Shell (30%), Elf

Petroleum Nigeria Limited — a subsidiary of Total — (10%), and Agip (5%). SPDC's operations

include a network of pipelines, nine gas plants, and two export terminals. Shell owns 100 percent of

SNEPCo, which was formed in 1993 to develop Nigeria's deepwater oil and gas resources offshore.

Under a PSC with NNPC, it operates the Bonga deepwater oil and gas project and is a venture partner in

the Erha deepwater oil and gas project with ExxonMobil.

ExxonMobil, the second largest IOC, operates fields producing approximately 800,000 bbl/d (700,000

bbl/d of crude) in partnership with NNPC. Chevron is the third largest oil producer in Nigeria and

produced an average of 516,000 bbl/d of crude oil in 2011. The company operates under its subsidiary,

Chevron Nigeria Limited, and holds 40 percent interest in 13 concessions under a joint venture

arrangement with NNPC. Most of its oil projects are in shallow water and onshore in the Niger Delta.

Chevron also has interests in deepwater projects, particularly its largest deepwater discovery Agbami.

Total and Eni are the fourth and fifth largest oil producers in the country, producing 179,000 bbl/d and

96,000 bb/d in 2011, respectively. Total operates several offshore projects and one onshore. Total is the

operator of the Usan deepwater field that came online in July 2012. Total's smaller share of production

has been unaffected in recent years whereas Eni/Agip has had some incidents, specifically at the Brass

River terminal that have shut-in varying volumes of production since December of 2006.

Exports

In 2011, Nigeria exported approximately 2.2-2.3 million bbl/d of crude oil, according to an analysis of

data from the Global Trade Atlas (GTA), APEX Tanker Data (Lloyd's Maritime Intelligence Unit), and

OPEC. Crude production estimates are sometimes less than crude export estimates for Nigeria due to oil

theft, particularly from the wellhead, that reduces the amount of official oil sales and makes it difficult

to estimate production.

Nigeria is an important oil supplier to the United States. In 2011, 767,000 bbl/d of crude (33 percent) of

Nigeria's crude exports were sent to the United States, making Nigeria the fourth largest foreign oil

supplier to the United States. Although Nigeria's high-quality light, sweet crude is a preferred gasoline

http://www.eia.gov/countries/analysisbriefs/Nigeria/images/oil_production_consumption.png


E N E R G Y D e s k

Page 24

feedstock, United States imports of Nigerian crude have decreased in volume and as a share of total

imports in 2011, with the trend continuing in 2012. According to an EIA article published earlier this

year, although total crude imports into the United States are falling, imports from Nigeria have declined

at a steeper rate. The main reasons underlying this trend are that some Gulf Coast refiners have reduced

Nigerian imports in favor of domestically-produced crude, and that two refineries in the U.S. East

Coast, which were significant buyers of Nigerian crude, were idled in late 2011. As a result, Nigerian

crude as a share of total United States imports has fallen to 5 percent in the first half of 2012, down

from 10 and 11 percent in the first half of 2011 and 2010, respectively, according to EIA.

Despite shut-in production, Nigerian oil trade patterns appear to have remained stable over the past

several years, most of which can be attributed to capacity additions and shifting world demand. Other

major importers of Nigerian crude oil include Europe (28 percent), India (12 percent), Brazil (8

percent), Canada (5 percent), and South Africa (3 percent). According to the Energy Intelligence

Group's International Crude Oil Market Handbook, Nigeria has about 20 exported crude streams and

most are light, sweet grades, with gravities ranging from API 29 — 47 degrees and low sulfur contents

of 0.05 — 0.3 percent.

Natural gas :

Nigerian LNG exports to the U.S. substantially declined in 2011, while the country's LNG exports to

Japan more than tripled in 2011.

Nigeria had an estimated 180 trillion cubic feet (Tcf) of proven natural gas reserves as of the end of

2011, according to the OGJ, making Nigeria the ninth largest natural gas reserve holder in the world and

the largest in Africa. Despite holding a top 10 position for proven natural gas reserves, Nigeria produced

about 1 Tcf of dry natural gas in 2011 and ranked as the world's 25th largest natural gas producer. The

majority of the natural gas reserves are located in the Niger Delta and, therefore, the sector is also

impacted by the same security and regulatory issues affecting the oil industry.

Most of Nigeria's marketed natural gas is exported as Liquefied Natural Gas (LNG), with the remainder

consumed domestically and other portions exported regionally via the West African Gas Pipeline. Shell

Nigeria Gas Limited (SNG), a Shell-owned gas sales and distribution company, also delivers

Compressed Natural Gas (CNG) to industries as far as 62 miles away from existing pipelines.

Dry natural gas production grew for most of the last decade until Shell declared a force majeure on gas

supplies to the Soku gas-gathering and condensate plant in November 2008. Shell shut down the plant

to repair damages to a pipeline connected to the Soku plant that was sabotaged by local groups

http://www.eia.gov/todayinenergy/detail.cfm?id=5770

http://www.eia.gov/dnav/pet/pet_move_impcus_a2_nus_ep00_im0_mbbl_m.htm

http://www.eia.gov/countries/analysisbriefs/Nigeria/images/crude_oil_exports.png


E N E R G Y D e s k

Page 25

siphoning condensate. The plant reopened nearly 5 months later, but was shut down again for most of

2009 for operational reasons. The Soku plant provides nearly half of the feed gas to Nigeria's sole LNG

facility; therefore, its closure led to a reduction in Nigeria's natural gas production, particularly from

Shell's fields in the Niger Delta, and a 33 percent decline in LNG exports in 2009. Gas production

partially recovered in 2010 after the plant reopened.

Sector organization

For the most part, the same national regulatory bodies and international oil companies (IOCs) involved

in Nigeria's oil industry are also the actors involved in the gas industry. The Nigerian Gas Company

Limited (NGC), a subsidiary of NNPC, is tasked with the marketing, transmission, and distribution of

gas and oversees pipeline projects. The PIB proposes to divide the NGC into two organizations: the

midstream National Gas Transportation Company, and a downstream gas marketing company. Like in

the oil industry, NNPC holds interest in gas projects alongside international oil companies.

International oil companies in Nigeria:

Shell dominates gas production in the country, as the Niger Delta, which contains most of Nigeria's gas

resources, also houses most of Shell's hydrocarbon assets. Shell produced 707 MMcf/d of gas in 2011

and its latest gas project, the Gbaran-Ubie integrated oil and gas project, achieved peak gas production

of 1 Bcf/d in early 2011. Gbaran-Ubie's gas is delivered to domestic power plants and to NLNG for

export.

The second largest gas producer, Total, produced 534 MMcf/d in 2011. Total, along with Eni, is

developing the Brass LNG facility, which will comprise two trains with the capacity of processing 5

million metric tons per year of LNG sometime after 2014. Eni was the third largest natural gas producer

in Nigeria in 2011. The company's natural gas output grew by almost 40 percent in the last three years

and reached 354 MMcf/d in 2011. Chevron produced 343 MMcf/d in 2011 and is majority owner of

major gas projects in the country, such as the WAGP and the Escravos GTL plant, as noted above.

Gas flaring:

Since Nigeria's oil fields lack the infrastructure to produce and market associated natural gas, much of it

is flared. According to the National Oceanic and Atmospheric Administration (NOAA), Nigeria flared

536 Bcf of natural gas in 2010 – or about a third of gross natural gas produced in 2010, according to

NNPC. In 2011, the NNPC claimed that flaring cost Nigeria US $2.5 billion per year in lost revenue.

The Nigerian government has been working to end natural gas flaring for several years, but the deadline

to implement the policies and fine oil companies has been repeatedly postponed with the most recent


E N E R G Y D e s k

Page 26

deadline being December 2012, which appears unlikely to be enforced. In 2009, the Nigerian

government developed a Gas Master Plan that promotes investment in pipeline infrastructure and new

gas-fired power plants to help reduce gas flaring and provide much-needed electricity generation.

However, progress is still limited as security risks in the Niger Delta have made it difficult for IOCs to

construct infrastructure that would support gas monetization.

Gas to liquids (GTL) :

A Chevron-operated Escravos Gas to Liquids (GTL) project is currently underway. The project is a joint

venture with NNPC and South Africa's Sasol and began in 2008. Escravos GTL has faced multiple

delays and cost overruns, but is currently scheduled to be operational by 2013. The project will convert

325 million cubic feet of natural gas per day into 33,000 barrels of liquids, principally synthetic diesel,

to supply clean-burning, low-sulfur diesel fuel for cars and trucks, according to Chevron.

Exports

Liquefied natural gas (LNG)

A significant portion of Nigeria's marketed natural gas is processed into LNG. In 2010, Nigeria

exported 17.97 million metric tons (875 Bcf) of LNG, making Nigeria the fifth largest LNG exporter in

the world and the largest LNG exporter in the Atlantic Basin. Furthermore, Nigeria's LNG accounted

for 8 percent of the total supplied to the world market and 30 percent of LNG coming from the Atlantic

Basin in 2010. However, although Nigeria's market share of LNG trade in the Atlantic Basin has been

increasing, mainly due to decreased LNG exports from Algeria, the country's market share in the world

has decreased from the 10 percent it once held to 7 percent, as reported by Nigeria Liquefied Natural

Gas (NLNG) Limited in 2012. Nigerian LNG exports rose to 18.86 million metric tons (918 Bcf) in

2011, but due to no recent capacity increases and rising production from Qatar and Australia, Nigeria's

world market share of LNG is slipping. Nigeria's LNG production capacity is currently 22 million

metric tons per year, and any major increase is not expected to come online before 2015.

In 2010, most of Nigeria's LNG was exported to Europe (67 percent), mainly Spain (31 percent), France

(16 percent) and Portugal (12 percent), with smaller amounts to Turkey, United Kingdom, and Belgium.

Other export destinations include Asia (15 percent) and North America (14 percent). The U.S. imported

0.86 million metric tons (42 Bcf) of Nigerian LNG in 2010, providing 1 percent of total U.S. LNG

imports.

In 2011, U.S. imports of Nigerian LNG significantly decreased to 0.05 million metric tons (2.5 Bcf),

according to EIA data, which is the lowest level recorded since Nigerian LNG exports began. In 2011,

more of Nigeria's LNG exports were sent to Japan and other Asian countries due to higher demand for

http://www.eia.gov/countries/analysisbriefs/Nigeria/images/gas_flaring.png


E N E R G Y D e s k

Page 27

LNG imports in those countries. Most notably, Nigerian exports to Japan more than tripled in 2011, as

Japan's LNG demand increased due to the Fukushima nuclear accident.

The Nigeria Liquefied Natural Gas (NLNG) facility on Bonny Island is Nigeria's only LNG complex.

NLNG partners, including NNPC (49 percent), Shell (25.6 percent), Total (15 percent), and Eni (10.4

percent), completed the first phase of the facility in September 1999. NLNG currently has six trains and

a production capacity of 22 million metric tons per year (1.1 Tcf). A seventh train is under construction

to increase the facility's capacity by 8 million metric tons per year. However, regulatory and political

issues, particularly regarding the long-delayed PIB, have delayed the project's start date to beyond 2014.

Three additional LNG plants with a total of seven trains were expected to come online after 2012, but

their expected start dates have been postponed beyond 2016. Plans include OK LNG (4 trains), Brass

LNG (2 trains), and Progress LNG (1 train). These are in varying stages of development, and

investment decisions will depend heavily on security, world LNG markets, and the final outcome of the

PIB. Availability of natural gas for export will also depend on Nigerian efforts to expand the use of

natural gas for domestic electricity generation – efforts that are included in both the Gas Master Plan

and the PIB.

International pipelines

Nigeria began exporting some of its natural gas via the West African Gas Pipeline (WAGP)in 2011. The

pipeline is operated by the West African Gas Pipeline Company limited (WAPCo), which is owned by

Chevron West African Gas Pipeline Limited (36.7%), Nigerian National Petroleum Corporation (25%),

Shell Overseas Holdings Limited (18%), Takoradi Power Company Limited (16.3%), Societe Togolaise

de Gaz (2%), and Societe BenGaz S.A. (2%).

The 420-mile pipeline carries natural gas from Nigeria's Escravos region to Togo, Benin, and Ghana.

WAGP links into the existing Escravos-Lagos pipeline and moves offshore at an average water depth of

35 meters. According to WAPCo, roughly 85 percent of the gas is used for power generation and the

remainder for industrial applications. Current recipients are Volta River Authority's Takoradi Thermal

Power Plant in Ghana and Electricity Community of Benin (CEB), a company co-owned by Benin and

Togo. Exports should eventually reach initial capacity of 170 million cubic feet per day (MMcf/d) and

plans are underway to expand capacity to as much as 460 MMcf/d and possibly extend the pipeline

further west to Cote d'Ivoire.

As of early October 2012, the pipeline is shutdown due to a loss of pressure around the Lome segment

that it experienced at the end of August 2012. The WAPCo has noted that maintenance to the damaged

pipeline is planned for completion at the end of December.

Nigeria and Algeria continue to discuss the possibility of constructing the Trans-Saharan Gas Pipeline

(TSGP). The 2,500-mile pipeline would carry natural gas from oil fields in Nigeria's Delta region to

Algeria's Beni Saf export terminal on the Mediterranean and is designed to supply gas to Europe. In

2009, the NNPC signed a memorandum of understanding (MoU) with Sonatrach, the Algerian national

oil company, to proceed with plans to develop the pipeline. Several national and international

companies have shown interest in the project, including Total and Gazprom. Security concerns along

the entire pipeline route, increasing costs, and ongoing regulatory and political uncertainty in Nigeria

have continued to delay this project.

http://www.eia.gov/countries/cab.cfm?fips=JA

http://www.wagpco.com/


E N E R G Y D e s k

Page 28

Conclusion:

Overall note of African countries for NG export with ranking:

Rank 1 :

Algeria:

With current export provision of 152 MMSCMD with current gas reserves for 50 Years with the

current level of production of 231 MMSCMD.

Rank 2 :

Nigeria:

With current export of 65 MMSCMD with Reserve of 140 MMSCMD( 100 yrs basis) or 176 yrs

reserves with current production level of 79 MMSCMD.

Rank 3 :

Egypt:

With a current export of 41 MMSCMD with reserve for 35 yrs with current level of production of 165

MMSCMD.

Rank 4 :

Mozambique:

Due to very less current consumption level (0.2 MMSCMD) in country , Export is possible at current

level of 8.3 MMSCMD with some NG reserve as on date . New E&P activities are on , so new

opportunities are expected to come.

Rank 5 :

Tanzania:

Very little NG gas consumption, & Reserves unless new discoveries takes place.

Remarks:

The ranking is done based on NG production, Reserve, export provision at current level (2010-11 basis).

E&P Developments & Govt. Laws, Geo political issues , Geo graphical position etc have not been

considered for while ranking at this moment.

Countries like Angola and others from African continent would be covered for closer view suitably.

http://www.eia.gov/countries/analysisbriefs/Nigeria/images/lng_exports.png

http://www.eia.gov/countries/analysisbriefs/Nigeria/images/west_african_gas_pipeline_map.png


E N E R G Y D e s k

Page 29

C. Top NG Exporting countries in World :

Rank country (cu m) Date of Information

1 World 1,098,000,000,000 2010 est.

2 Russia 203,900,000,000 2011 est.

3 Norway 98,300,000,000 2011 est.

4 Qatar 94,900,000,000 2010 est.

5 European Union 93,750,000,000 2010 est.

6 Canada 92,720,000,000 2011 est.

7 Algeria 55,790,000,000 2010 est.

8 Netherlands 54,800,000,000 2011 est.

9 United States 42,670,000,000 2011 est.

10 Indonesia 41,250,000,000 2010 est.

11 Malaysia 31,990,000,000 2010 est.

12 Australia 25,530,000,000 2011 est.

13 Turkmenistan 24,900,000,000 2010 est.

14 Nigeria 24,020,000,000 2010 est.

15 Trinidad and Tobago 20,380,000,000 2010 est.

16 Germany 19,740,000,000 2011 est.

17 United Kingdom 16,690,000,000 2011 est.

https://www.cia.gov/library/publications/the-world-factbook/geos/xx.html

https://www.cia.gov/library/publications/the-world-factbook/geos/rs.html

https://www.cia.gov/library/publications/the-world-factbook/geos/no.html

https://www.cia.gov/library/publications/the-world-factbook/geos/qa.html

https://www.cia.gov/library/publications/the-world-factbook/geos/ee.html

https://www.cia.gov/library/publications/the-world-factbook/geos/ca.html

https://www.cia.gov/library/publications/the-world-factbook/geos/ag.html

https://www.cia.gov/library/publications/the-world-factbook/geos/nl.html

https://www.cia.gov/library/publications/the-world-factbook/geos/us.html

https://www.cia.gov/library/publications/the-world-factbook/geos/id.html

https://www.cia.gov/library/publications/the-world-factbook/geos/my.html

https://www.cia.gov/library/publications/the-world-factbook/geos/as.html

https://www.cia.gov/library/publications/the-world-factbook/geos/tx.html

https://www.cia.gov/library/publications/the-world-factbook/geos/ni.html

https://www.cia.gov/library/publications/the-world-factbook/geos/td.html

https://www.cia.gov/library/publications/the-world-factbook/geos/gm.html

https://www.cia.gov/library/publications/the-world-factbook/geos/uk.html


E N E R G Y D e s k

Page 30

18 Egypt 15,170,000,000 2010 est.

19 Uzbekistan 14,400,000,000 2010 est.

20 Bolivia 11,720,000,000 2010 est.

Two African countries namely Algeria & Nigeria takes place in top 20 NG gas export countries

whose details are mentioned above.

Top 10 Proven Gas reserve countries :

Two countries namely Algeria & Nigeria from African continent also in the the list of top 10 Gas

reserves in the World list whose details have been deliberated above in the closer view.

D. Crude import in India from countries - The fact Sheet :

2010-11 10^3 barrel/Day Million Barrel/Day MMTPA

Saudi Arabia 549 0.549 27.89

Iran 372 0.372 18.90

Iraq 345 0.345 17.53

UAE 294 0.294 14.94

Kuwait 231 0.231 11.74

Oman 104 0.104 5.28

Qatar 113 0.113 5.74

Venezuela 207 0.207 10.52

Nigeria 318 0.318 16.16

Angola 194 0.194 9.86

https://www.cia.gov/library/publications/the-world-factbook/geos/eg.html

https://www.cia.gov/library/publications/the-world-factbook/geos/uz.html

https://www.cia.gov/library/publications/the-world-factbook/geos/bl.html

http://www.eia.gov/countries/analysisbriefs/Nigeria/images/proven_natural_gas.png


E N E R G Y D e s k

Page 31

Sub Total 2727 2.727 138.55

Rest 573 0.573 29.11

Total import 3300 3.3 167.67

Note:

India is importing @166 MMTPA crude , a 10$/barrel increase in crude price to cost about Rs 60000

Crores/Annum extra import bill.

E. CO2 Transportation through Pipeline :

The most efficient state of CO2 for pipeline transport is as a dense-phase liquid as, in this phase, the fluid has

the density of a liquid, but the viscosity of a gas. In this ‘supercritical’ mode, captured CO2 has to be

compressed to a pressure above the critical pressure prior to transport.

Currently, there is little published work on transport of CO2 with these impurities, the main effect of which is

to change physical properties such as the critical pressure, which can have a consequent dramatic impact on

the CO2’s hydraulic behaviour. This in turn may change the operating regime of the pipeline, which may have

to be operated at a higher pressure than would be required for pure CO2 in order to maintain it as single-phase

supercritical or dense-phase.

The presence of impurities in the CO2 stream will not only have a significant effect on the hydraulic

parameters such as pressure and temperature, but also on the density and viscosity of the fluid, depending on

the impurities present. Some combinations, particularly if hydrogen or nitrogen are present, cause higher

pressure and temperature drops for a given pipeline length than others, which has implications for the distance

between compressor stations along the pipeline. The pipeline cost increases with the number of these which,

in any event, are not viable for subsea pipelines. Sudden temperature drops can have potential material

implications, such as embrittlement, and can also cause hydrate formation, both of which could damage the

pipeline.

The solvent properties of supercritical CO2 are known to be detrimental to the elastomers commonly used in

valves, gaskets, and O-rings, used for sealing purposes, and to coatings. At high pressures the supercritical

CO2 diffuses into the elastomers and, when the pressure is reduced, blistering and even explosions can occur

as the material decompresses. Many of the elastomeric materials currently used in oil and gas pipelines are

therefore not suitable for CO2 transportation. Similarly, in-line inspection (ILI) of CO2 pipelines is

problematic, as the supercritical CO2 dissolves the non-metallic components of the cleaning and ILI and tools:

although high-durometer elastomers can be used to reduce the problem, they cannot eliminate it totally.

There are other important material issues that will require consideration in CO2 pipeline design. Ductile

fracture propagation may be an issue, and the requirement to consider fracture propagation in CO2pipelines is

included in the federal regulations in the US. For some of the US pipelines it was concluded that the pipe

material did not have sufficient toughness to arrest propagating ductile fractures and therefore crack arrestors

were required along these pipelines. This experience highlights the need to define the toughness limits for

equivalent pipeline networks, particularly considering the effect of impurities on the decompression behaviour

of the gas, to avoid the costly requirement to fit crack arrestors. In the US the CO2 pipelines were designed-

for-purpose: if pipeline re-use is to be adopted in the UK and elsewhere, existing pipelines will have to be

assessed extremely carefully bearing all of these factors in mind.

Metal Embrittlement – Toughness versus Temperature:

Pipeline steels show a ductile-to-brittle transition at low temperatures and the toughness value of the material,

i.e. the resistance to brittle fracture, is reduced at lower temperatures. Knowledge of the exact behaviour of the

material is key in the development of a structural integrity model for the pipeline. As part of the development


E N E R G Y D e s k

Page 32

of the model, a database containing toughness characteristics of the material as a function of temperature

should be compiled.

Technically, CO2 can be transported through pipelines in the form of a gas, a supercritical fluid or in the

subcooled liquid state. Operationally, most CO2 pipelines used for enhanced oil recovery transport CO2 as a

supercritical fluid. Supercritical fluid and subcooled liquid transport are examined and compared, including

their impacts on energy efficiency and cost. Using a commercially available process simulator, ASPEN PLUS

10.1, the results show that subcooled liquid transport maximizes the energy efficiency and minimizes the cost

of CO2 transport over long distances under both isothermal and adiabatic conditions. Pipeline transport of

subcooled liquid CO2 can be ideally used in areas of cold climate or by burying and insulating the pipeline. In

very warm climates, periodic refrigeration to cool the CO2 below its critical point of 31.1 °C, may prove

economical.

Differences between safe flow and choking point for varying CO2 pipe inlet temperatures at

adiabatic condition (pipe inlet pressure = 15.0 MPa (152 Kg/Cm2 )


E N E R G Y D e s k

Page 33

CO2 density changes along pipeline at different inlet temperatures (pipe inlet

pressure = 15.0 MPa; Iso.—isothermal condition; Adi.—adiabatic condition).

Cross section of the pipeline underground. Comparison between adiabatic and isothermal

transmission (pipe

inlet pressure = 15.0 MPa; pressure drop = 7.0 MPa).

Pressure drop along pipeline at different pipe inlet conditions (without boosters).

CO2 critical parameters: Tc = 31.1 °C; Pc = 7.38 MPa; ρc = 0.47 g/cm3.

So, with all above technicality , there are several pipelines already exists mainly for sequestration purpose for

a long length pipeline.


E N E R G Y D e s k

Page 34

The pipelines which exist for CO2 upto flare stack for release from process is small distance pipelines to cater

the process requirements

Existing CO2 Pipeline with some details :

A. Pipeline Route

The CO2 pipeline is 204.8 miles from Dakota Gas to the GoodWater Unit, which is part of Cenovus

Energy's Weyburn oil field. Once the pipeline enters Canada it is known as the Souris Valley Pipeline for

the area it passes through. Souris Valley Pipeline Ltd. is a wholly owned subsidiary of Dakota Gas. The

North Dakota segment of the pipeline system begins with the 14" pipe heading west out of Dakota Gas,

paralleling an existing power line corridor and various section line roads.

Near the town of Dunn Center, the route begins a northwesterly bearing. Near the crossing of Highway 22, the

route assumes a northerly alignment as it passes east of the Killdeer Mountains and crosses the Little Missouri

River. This northerly track continues for approximately 95 miles, crossing Lake Sakakawea at pipeline

milepost 98, and passing just east of the town of Tioga, where a booster pump station is located.

The pipeline reduces to a nominal 12-inch diameter on the discharge side of the Tioga Booster Station. North

of the town of McGregor, the route turns to the northwest, running approximately 20 miles, crossing Highway

5 between the towns of Noonan and Crosby. This northwesterly track continues until reaching the

Saskatchewan border.

The Canadian portion of the pipeline crosses the border southwest of Estevan and takes a northerly track

roughly parallel to the Souris River, until reaching the delivery point just north of the town of Good Water.

The pipeline was routed to provide a one thousand-foot buffer zone from centerline of the pipeline to any

Canadian occupied residence, this exceeds both United States and Canadian requirements. In 2005, a second

Canadian customer, Apache, was brought on-line.

B. Map:

C. Purpose and operating limits

The CO2 pipeline was designed to transport up to 240 mmscfd carbon dioxide on a continuous basis to the

Tioga Station and continue with 160 mmscfd from Tioga to the GoodWater Unit. Beginning in 2000, the CO2

pipeline began to supply approximately 94 mmscfd of carbon dioxide to PanCanadian’s Weyburn Unit in

Saskatchewan, Canada, for injection into their oil field. This injection process was expected to boost


E N E R G Y D e s k

Page 35

PanCanadian’s oil production from the current 14 Mbbl/d to a high of 34 Mbbl/d. Benefits of the carbon

dioxide injection were expected to last for 12 to 14 years at 20 bb/d before production levels begin to drop.

Currently, with three compressor at Dakota Gas and a booster pump at Tioga, a total of approximately 150

mmscfd of CO2 is supplied to Cenovus Energy and Apache for use in Enhanced Oil Recovery (EOR).

The maximum allowable operating pressures (MAOP) for the pipelines are as follows:

Line size & grade MAOP Hydrotest Pressure

14" OD x 0.375" WT Grade X70 2700 psig 3375 psig

12.75" OD x 0.375" WT Grade X70 2964 psig 3705 psig

D. Pipeline cover requirements

The CO2 pipeline was designed with 14" x 0.375"WT and 12.75" x 0.375"WT ERW pipe for general use, a

minimum of 48" of ground cover was maintained for the length of the pipeline. At road crossings 0.500"WT

SMLS Grade X65 heavy wall pipe was used for a minimum of one foot past the road right-of-way, a

minimum of 5 feet of cover beneath the road and 4 feet of cover beneath the ditches was maintained. Railroad

crossings required 0.625"WT SMLS X65 extra heavy wall pipe be used. All railroad crossings were bored

with a minimum of 10 feet of cover allowing a minimum of 4 feet of cover in the ditches.

The Little Missouri River and Lake Sakakawea crossings were made with heavy-wall pipe the difference in

the two crossings being that the pipe was buried and covered with rock on the Little Missouri and on Lake

Sakakawea the pipe lays on the bottom and is buried only at the banks for 10 feet below the water line. The

crossing of Jewel Creek in Canada was handled the same as the Little Missouri crossing.

All buried piping was coated with fusion bonded epoxy to prevent corrosion, in addition all piping used at

bored crossings was overcoated with a abrasion resistant coating to prevent damage to the epoxy during

installation.

E. Cathodic protection

To protect the pipeline from external corrosion a impressed current cathodic protection system is used.

Cathodic protection on the CO2 pipeline is maintained by rectifiers located at MLV01, MLV03, MLV04,

MLV05, MLV06, MLV07, Tioga Station, MLV08, MLV09 and MLV11. The cathodic protection is

measured in voltage at test posts located at one-mile intervals over the length of the pipeline. We adjust

the rectifier output to maintain voltage levels between .85 and 1.4 volts at each test station.

F. Pipeline maintenance

Activities on the pipeline fall basically into two categories, preventive maintenance and patrols. The

exception to this is the locate request we receive from those folks wanting to excavate on our right-of-

way or cross the pipeline. Once a locate request is received the pipeline staff locate and mark the pipeline,

when the actual excavation or crossing is done it is supervised until completed by Dakota Gas personnel.

Scheduled maintenance jobs with their annual frequency:

Aerial patrols, 26 times per year

Cathodic protection survey, once each calendar year

Emergency systems check once per year

Internal inspection of the pipeline using an electronic tool, every five years or more frequently, if

necessary

Overpressure safety devices, once each calendar year

Population density survey, once every two years

Public awareness and damage prevention program, once each calendar year

Rectifier maintenance,6 times each calendar year

ROW inspection, 26 times each calendar year

Valve maintenance and inspection, twice each calendar year


E N E R G Y D e s k

Page 36

CO2 pipeline in USA:

Conclusion on Co2 transportation through Co2 pipeline:

It is apparent that the knowledge gained from current CO2 pipelines will prove vital, not only with regard to

experience and solutions, but also for those issues that have not been fully addressed, such as flow assurance,

dispersion, properties and engagement. These need to be resolved to enable deployment.

Despite these critical areas that need to be addressed, the body of evidence, experience and proven design

methodology, codes and regulation enables the design of CCS pipelines and infrastructure. This experience

may prove to be conservative and more costly, but it does not prevent pipelines from moving forward. The

industry must maximise the transfer of knowledge from CO2 and hazardous liquid pipeline design. In parallel,

research must address the issues discussed and generate resources and tools that can meet the challenge to

bring to wide scale deployment.

The Focussed Energy Report tries to capture all on-going issues, challenges, efforts & developments being

made Indian Oil & Gas industries keeping Global development & perspective in mind which relates finally

the GAIL’s business w.r.t energy.

The primary & secondary data, received from various journals, books, publications etc. are then checked,

verified and converted into useful information for kind perusal and for effective use as ready information with

a scope of updation on a regular interval.

Note:

The data and information in the report is sourced from websites and documents available in public

domain and doesn’t purport to be official view of government or any organization. Sincere efforts have

been made to present correct data; however, errors and omissions, if any, are regretted and the same

may please be brought to the notice of Energy Desk for necessary corrective action.

focused energy report - gailcorintra.gail.co.in · november 9, 2012 [focused energy report] ... wti...

Documents