Preparatory Study on Natural Gas Development and GTL ...€¦ · Total oil production of crude oil...

Preparatory Study on

Natural Gas Development and GTL Manufacturing Project in

Papua New Guinea (PNG)

Study Report

December 2004

Engineering and Consulting Firms Association, Japan

Pacific Consultants International

Preparatory Study on Natural Gas Development and GTL Manufacturing Project in Papua New Guinea (PNG), December 2004

1

1. Country Profile of PNG

1.1 Geography, Climate and Population

Papua New Guinea is the eastern half of the island of New Guinea – second

largest in the world – and located 6 °00’ S 147 °00’ E. The total land area is

452,960 km2 which is 1.25 times larger than Japan. The terrain is mostly mountain

with coastal low lands and rolling foot hills. Arable land is limited only to 1.3%.

Climate is tropical and having two distinct seasons with Northwest monsoon

season (December to March) and southeast monsoon (May to October). The

temperature varies slightly by season. The population is 5.2 million and its growth

rate is around 2.34% (See Table-1a.).

Of the total 5.2 million population, Highland Region accounts for 38% or 2.1 million.

The Highland Region is the area where the crude oil is produced. Southern

Highland Province is the core province of this region and its population is around

546,000 or accounts for around 11% of the total population of PNG. The average

altitude of this province is around 2,400 m from the sea level.

Geographic maps of overall PNG and Western PNG are shown in Figures-1a and

1b respectively.

1.2 History

New Guinea was divided between Germany (northern portion, presently New

Britain and New Island) and the UK (southern portion, presently Main Land) in

1885 when African countries are divided by European countries. The latter area

was transferred to Australia in 1902, which occupied the northern portion during

World War I and continued to administer the combined area until independence in

1975.

1.3 Economy

PNG is richly endowed with natural resources, but exploitation has been

hampered by rugged terrain and the high cost of developing infrastructure.

Agriculture provides a subsistence livelihood for 85% of the total population.

Mineral deposits, including oil and gas, copper and gold, accounts for 46% of


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export earnings. The economic growth is registered at 2.0% per annum in year

2003 and gradually recovering from the past stagnation. GDP per capita is

estimated at US$530. GDP is composed of agriculture 32.1%, industry 35.8% and

services 32.1%. The population below poverty line is estimated to be around 37%.

Number of labor force is 2.3 million and mostly engages with agriculture (85%).

The total expenditure of the government was US$ 1.1 billion including capital

expenditures of US$ 344 million in 2000.

1.4 Industry

Major industry is crude oil production, copra crushing, palm oil processing,

plywood production, wood chip production, mining of gold, silver and copper,

construction and tourism. Most of the industry is primary industry based on natural

resources such as mineral oil, mineral, forest, and agricultural products. Total oil

production of crude oil reached to 67,500 bpd (2000 estimates) and domestic

consumption is 15,000 bpd. Proven oil reserve at present is 345 million bbl.

1.5 Trade

The total amount of exports reached to US$ 3.6 billion in 2002, which composes

mineral products (crude oil, gold, copper, ore, logs, etc.), palm oil, cocoa, prawns,

etc. The mineral products accounts for 33.4% of total export value. Export partners

are Australia (42.0%), Singapore (8.9%), Germany (6.9%), Japan (6.4%), USA

(6.3%), UK (5.5%), China (4.7%), and South Korea (1.7%) in 2002. The total

amount of import is US$ 4.6 billion which composes mineral fuel (14.0%),

machinery and transport equipment, manufactured goods, food, fuels, chemicals,

etc. Import partners are Australia (59.2%), USA (8.7%), Japan (5.2%), New

Zealand (4.0%), UK (3.3%), Malaysia (2.2%) and Indonesia (2.0%). The

accumulated external debt is US$2.8 billion (See Table-1b.).

As such Australia is the largest and most important trade partner and Japan and

UK follow. The reason why the value of trade with Singapore and USA is

substantially high is that the crude oil is exported to Singapore and USA and

petroleum products such as automotive fuel is imported from Singapore.


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Table-1a Population by Region (PNG 2002 Census)

Region Population Percent (%) Population Percent (%)

Papua New Guinea 5,190,777 100%

Southern Region 1,041,820 20%

Western Province 153,304 3%

Gulf Province 106,898 2%

Central Province 183,983 4%

National Capital District 254,158 5%

Milne Bay Province 210,412 4%

Northern Province 133,065 3%

Highlands Region 1,973,987 38%

Southern Highlands Province 546,256 11%

Enga Province 295,031 6%

Western Highlands Province 440,025 8%

Chimbu Province 259,703 5%

Eastern Highlands Province 432,972 8%

Momase Region 1,433,432 28%

Morobe Province 539,404 10%

Madang Province 365,106 7%

East Sepik Province 343,181 7%

West Sepik Province 185,741 4%

Island Region 741,538 14%

Manus Province 43,387 1%

New Ireland Province 118,350 2%

East New Britain Province 220,133 4%

West New Britain Province 184,508 4%

North Solomon Province 175,160 3%


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Table-1b PNG Exports and Imports (PNG 2002 Census)

Amount (US$1,000)

Percentage (%)

(Exports)

All Sector 3,568,861 100.00

Mineral Products (oil) 1,193,250 33.44

Pearl, Precious Stone and Metal 448,085 12.56

Animal or Vegetable Fats and Oil 408,975 11.46

Wood, sawn wood, etc. 408,641 11.45

Vegetable Products 315,957 8.85

Live Animal and Animal Products 270,847 7.59

Processed Food and others 260,896 7.31

Machinery 112,625 3.16

Transport Equipment 83,927 2.35

Base Metal 22,164 0.62

Chemical or Allied Industries 2,791 0.08

Plastic Articles 9,722 0.27

Raw Hide and Skins 2,742 0.08

Stone, Plaster, Cement, etc. 1,682 0.05

Miscellaneous Manufactured Items

1,039 0.03

Textile and Textile Articles 471 0.01

Footwear 47 0.00

Others 25,000 0.70

(Imports)

All Sector 2,275,113 100.00

Mineral Products 649,957 28.57

Vegetable Products 336,868 14.81

Chemical or Allied Industries 312,819 13.75

Live Animal and Animal Products 187,928 8.26

Processed Food 185,756 8.16

Plastic Articles 242,871 10.68

Pulp of Wood 166,319 7.31

Textile and Textile Articles 129,063 5.67

Animal or Vegetable Fats and Oil 53,032 2.33

Raw Hides and Skins 5,728 0.25

Wood 4,772 0.21


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2. Petroleum Resources in PNG

2.1 Natural Resources Development Policy

PNG endows vast volume of natural resources such as forest resources, mining

resources such as gold and copper, hydrocarbon resources such as petroleum

crude oil and gas. Since the independence-day various policies has been

formulated to invite foreign investors to exploit such resources aiming to secure

the revenues of the government for the sake of peoples’ welfare through the

economic and resource development. In 1976, the first White Paper titled

“Statement on Petroleum Policy and Legislation” outlining the Government’s policy

on petroleum exploration and development was issued just after Papua New

Guinea became independent. The exploratory efforts carried out and the potential

for substantial oil and gas reserves was indicated but no petroleum fields were

under production on commercial basis until 1992.

2.2 Contribution of Petroleum in National Economy

During 1992 – 1998, crude oil exports accounted fro 27% of the total value of PNG

exports. In 2002, the petroleum accounted for 12% of GDP and 33.4% of total

exports. These figures indicate the importance of the industry to the national

economy similar to that of mining sector. The economy of Papua New Guinea is

very dependent on the petroleum and mining industries, accounting for about 60%

of total exports.

By the end of June 1995, the volume of crude oil exported reached to 126 million

barrel valued at US$2.2 billion. Although the crude oil production has been

declining, the crude oil exports continued to be a major source of revenue and

foreign exchange for PNG. A record high crude oil price in the international market

in 2004 may bring additional foreign exchange to PNG from the export of crude oil.

PNG endows a fairly large volume of gas reserve especially in Papua Basin which

across the Southern Highland Region. If this gas is developed fully and contribute

to the national economy its impact would be substantially high. The impact to

national economy, when whole gas reserved is commercialized is enormous.

2.3 Petroleum Exploration and Development History

Petroleum exploration in PNG dates back to early 1900s following reports of gas


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seeps along the lower Vailala River by early gold prospectors. The German in New

Guinea and the Australian likewise in Papua did exploration efforts separately

when the country was colonized as mandated colonies by these former empires.

Over 285 wells have been drilled in the country most of those within the Papuan

Basin. The Papuan Basin by large has attracted a lot of attention in terms of

exploration and drilling, and is currently the only producing basin whereas the

other four basins only rank as frontier basin.

Twenty-seven field discoveries have made in the Papuan Basin since initial

inception of exploration dating back to 1913. Of the fields that have been

discovered to date only four fields (Hides, Kutubu, Gobe and Moran) are currently

the only producing fields. PNG has a total in place hydrocarbon reserves of

approximately 1.2 billion barrels of oil equivalent (boe) and about 22 TCF of gas

reserves. Of these the total countrywide recoverable reserves sum up to about

430 million barrels of oil, 200 million barrels of condensate, and 15 TCF of gas.

Most of these reserves are concentrated in a linear trend spreading NW-SE along

the Papuan Fold and Thrust Belt (PFTB).

Currently seventeen (17) Petroleum Prospecting Licenses (PPLs), five (5)

Petroleum Development Licenses (PDLs), three (3) Pipelline Licences (PLLs), ten

(10) Petroleum Retention Licences and one (1) Petroleum Processing Facility

Licence (PPFL) were active in 2003.

Table-2a shows the summary of discoveries to date. Figure-2a shows onshore

main oil and gas fields in Papuan Basin, Western PNG. The PNG oil and gas

field concession is shown in Figures- 2b and - 2c.

Table-2a Discoveries of Oil and Gas Fields In PNG Original Operator

Field Discovery Year

Current Permit

Current Operator

Type of Discovery

Existing Wells in Fields

Province

Island Exploration

Barikewa 1958 PPL 189 Barracuda Gas 2 Gulf

APC Bwata 1960 PPL 191 Barracuda Gas/Condensate

1 Gulf

APC Iehi 1960 PPL 189 Barracuda Gas 1 Gulf Philips Uramu 1968 PPL 188 Oil Search Gas 1 Gulf Niugini Gulf

Juha 1983 APRL 2 Oil Search Gas/Condensate

3 Western


7

Oil Chevron Kutubu 1986 PDL 2 Oil Search Oil/Gas 47 SHP BP Hides 1987 PDL 1 &

PPL 138 Oil Search/ Esso

Gas/Condensate

4 SHP

Chevron SE Hedinia

1987 PDL 2 Oil Search Gas 5 SHP

Chevron Usano 1989 PDL 2 Oil Search Oil 2 SHP IPC Pandora 1988 PRL 1 IPC Gas 2 Gulf Chevron Agogo 1989 PDL 2 Oil Search Oil 1 SHP BP Angore 1990 PPL 138 Esso Gas/Condensa

te 1 SHP

BP Elevala 1990 PPL 157 Santos Gas/Condensate

1 Western

Chevron P’nyang 1990 APRL 3 Oil Search Gas/Condensate

2 Western

BP Ketu 1991 PPL 138 Esso Oil 1 SHP Command

SE Gobe 1991 PDL 3 Oil Search Oil/Gas 5 SHP/Gulf

Chevron SE Mananda

1991 PDL 2 Oil Search Oil/Gas 2 SHP

Chevron Gobe Main

1993 PDL 4 Oil Search Oil/Gas 6 SHP

BP Paua 1995 PPL 138 Esso Oil 1 SHP Chevron Moran 1996 PDL 5 Oil Search Oil 4 SHP Santos Stanley 1999 PRL 4 Santos Gas 1 Western Oil Search

Kimu 1999 PRL 8 Oil Search Gas 2 Western

Chevron Saunders

2002 PDL 4 Oil Search Oil 1 Gulf

Santos Bilip 2002 PPL 190 Santos Oil 1 Gulf Chevron/ Texaco

Morthwest Moran 1

2003 PPL 219 Oil Search Oil 6 SHP

Total SHP Total

Source: Department of Petroleum and Energy, Annual Report 2003 on Petroleum Activity Note: SHP means Southern Highland Province


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2.4 Oil, Natural Gas and Condensate Reserves

All of petroleum reserves discovered to data are located in the Papuan Basin both

onshore in the Foldbelt and offshore in the Gulf of Papua. As of 2001 the reserves

of oil/condensate and gas is estimated to be 567 MMbbl and 14,573 Bcf,

respectively. Papua New Guinea has vast quantities of indigenous gas reserves,

both on shore and offshore, which have remained undeveloped due to lack of local

demand. The reserves of oil/condensate and gas by province are as shown in

Table-2b. As shown in this table, Southern Highlands Province (SHP) accounts for

70% to total recoverable oil reserves and 46% of gas reserves.

Figure-2a Onshore Main Oil and Gas Fields in Papuan Basin,

Western PNG


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Table-2b Oil and Condensate Reserves by Province Field Discovery

Year Current Permit

Type of Discovery Existing

Wells in

Fields

Oil/Condensate. (MMbbl)

Gas (Tcf)

Province

In Production Gobe Main 1993 PDL 4 Oil/Gas 6 21 0 SHP SE Gobe 1991 PDL 3 Oil/Gas 5 40 0 SHP/Gulf Kutubu 1986 PDL 2 Oil/Gas 47 54 0 SHP Moran 1996 PDL 5 Oil 4 89 0 SHP

In Production Total 206 0 Technical Reserve

SE Hedinia 1987 PDL 2 Gas 5 3 0.150 SHP Usano 1989 PDL 2 Oil 2 SHP Agogo 1989 PDL 2 Oil 1 SHP Angore 1990 PPL 138 Gas/Condensate 1 12 0.900 SHP Ketu 1991 PPL 138 Oil 1 31 0.450 SHP Paua 1995 PPL 138 Oil 1 20 0 SHP NW Moran 1

2003 PPL 219 Oil 6 SHP

SE Mananda

1991 PDL 2 Oil/Gas 2 20 0.200 SHP

Hides 1987 PDL 1 & PPL 138

Gas/Condensate 4 110 5.000 SHP

SHP Sub-total (1) 206 0 SHP SHP Subtotal (2) 193 6.700 SHP

SHP Total 399 6.700 SHP SHP’s Share in Total (70%) (46%)

Barikewa 1958 PPL 189 Gas 2 0 0.390 Gulf Bwata 1960 PPL 191 Gas/Condensate 1 0 0.050 Gulf Iehi 1960 PPL 189 Gas 1 0 0.030 Gulf Uramu 1968 PPL 188 Gas 1 0 0.120 Gulf Pandora A 1988 PRL 1 Gas 2 0 1.200 Gulf Pandora B 0 0.400 Saunders 2002 PDL 4 Oil 1 Gulf Bilip 2002 PPL 190 Oil 1 Gulf Juha 1983 APRL 2 Gas/Condensate 3 55 1.300 Western Elevala 1990 PPL 157 Gas/Condensate 1 37 0.550 Western P’nyang 1990 APRL 3 Gas/Condensate 2 16 1.800 Western Stanley 1999 PRL 4 Gas 1 10 0.010 Western Kimu 1999 PRL 8 Gas 2 0 0.050 Western

Sub-total Gulf and Western

118 5.900

Others 50 1,.73

Grand Total 567 14.573 Source: Department of Petroleum and Energy, Annual Report 2003 on Petroleum Activity Notes: 1) SHP means Southern Highland Province 2) Volume is shown in Recoverable Reserves (2p=p+p) at 2001

2.5 Crude Oil Production

PNG joined the ranks of the oil-producing country on July 27, 1992 when the first

shipment of oil from the Kutubu field was exported. Production from Kutubu


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reached a peak production of over 120,000 bopd in 1993. The field reached its

plateau production in 1994 and has been steadily declining since 1995. In 1993

the annual outputs was 45 million barrels and it has declined steadily from there

down to about 7.3 million barrels in 2003. The averaged oil production of Kutubu in

2003 is recorded at 20,217 bopd.

The country saw production from its second oil field Gobe in 1998. The Gobe field

production reached a plateau of about 25,000 bopd before going back to the

decline phase. Gobe production reached its peak annual out put of 12.5 million

barrels in 1999 and have steadily decline from there down to about 5.7 million

barrels in 2002. The averaged oil production of Gobe in 2003 is recorded at

14,810 bopd.

The country’s third oil project Moran was put into production testing as early as

1998. This field reached its plateau at around 28,000 bopd. The full field

development in 2003 should see the annual oil outputs above 5.0 million barrel.

The averaged oil production of Moran in 2003 is recorded at 14,810 bopd.

Thus, the country’s total oil rates average between 50,000 and 52,000 bopd. Both

Kutubu and Gobe fields are mature producing fields that have gas capacity

constraints as most gas produced are re-injected into the reservoirs to maintain

reservoir pressures. Kutubu crude properties are as shown on Table-2c.

Table-2c

Kutubu Light Crude Oil Properties (Kutubu, Gobe and Moran)

Property Measured Gravity, API 45.1 Specific Gravity 0.8014 Sulfur 0.04 Total nitrogen, ppm 357 Hydrogen, wt% 13.9 Acid number, mg KOH/g 0.03 Pour point, °F/°C. 30/-1 Character factor (K-factor) 12.2 Viscosity, cSt@40°C（104°F） 2 Viscosity, cSt@50°C（122°F） 1.59 MCR, wt% 0.6 Ramsbottom carbon, wt% 0.4


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2.6 Crude Oil Refining

The Canadian company which is building PNG’s first commercial refinery, recently

entered into a share sale agreement with BP plc to BP’s PNG subsidiary, BP

Papua New Guinea Limited. Papua New Guinea’s first commercial refinery started

operation in June, 2004.

The refinery is expected to process 32,500 barrels of crude per day. It will

produce diesel, kerosene, Jet A -1 kerosene and petrol for the whole country.

Almost all of this will be converted into various salable products about 31,000

barrels in all. Up to 60 percent of product will be consumed by the domestic

markets, with export steam that includes shipment of naphtha to Korea and Japan,

fuel to Pacific Islands, and .possible sales of motor sprit and diesel to northern

Australian centers.

The InterOil refinery at Napa Napa has a deep water jetty capable of

accommodating crude oil tankers up to 18,0000 dwt. Crude oil storage is 750,000

barrels, part of total refinery storage capacity of 1.9 million barrels of crude and

product (See Figure-2d.). The facility is also sufficient in both and water.


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Notes: NG’s First Commercial Oil Refinery in Papa Napa on the opposite side of Port Moresby Harbor, Operated by InterOil Corporation, Canada. Removed an existing oil refinery in Alaska, USA to reinstall it at Napa Napa in Port Moresby Harbor. Start of operation: June, 2004. Capacity: 32,500 bpd.

Figure - 2d

Napa Napa Oil Refinery, InterOil Corporation, Canada

Refinery


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2.7 Natural Gas Production

Gas production in Papua New Guinea is still very much in its infancy. Despite a

wealth of gas reserves the country only produces less than 15 mmcfd of gas which

is supplied by the Hide gas field for use at a small power plant at Tagari, which in

turn supplies electricity to the mine site at Porgera.

In 1995, the proven reserve of gas was estimated as much as 14 Tcf. The

Government is aware that the upgrading of these reserves to the point where they

can be produced and used commercially will require a massive foreign investment

in exploration, appraisal and development of gas fields and in facilities such as

pipelines, gas processing plants and marine terminals. As the Government

recognized that the contractual and fiscal policies, largely designed for crude oil,

are inappropriate for attracting the investment needed for the production and

utilization of gas. Consequently, the Government issued the gas development

policies and subsequently issued Oil and Gas Act, No. 49 of 1998. Oil and Gas Act

1998 is an Act to enact comprehensive legislation governing the exploration for

and production of petroleum (including oil and gas) in PNG, including the offshore

area, and the grant to traditional landowners and Provincial Government and

Local-level Government of benefits arising from project for the production of

petroleum (including oil and gas), and the processing and transportation in PNG

and petroleum products.

Plans to commercialize the vast reserves of uncontracted gas at Kutubu, Gobe

and Hides involve gas export, either as LNG to North East Asia, or as pipeline gas

to North/Central Queensland.


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3. Oil and Gas Laws and Regulations in PNG

3.1 Licensing

Licensing is administered by the Petroleum Advisory Board (PAB) of the

Department of Petroleum and Energy (DPE). Three forms of petroleum licenses

are applicable to the upstream sector; a Petroleum Prospecting License (PPL),

covering the initial exploration phase, a Petroleum Development License (PDL),

covering the development and production phase, and a Petroleum Retention

Licence (PRL), applicable gas fields with perceived long lead times between the

exploration and development phases. In addition to these licenses, the Oil and

Gas Act 1998 introduced a Petroleum Processing Facility License (PPFL) and

amended the existing Pipeline License (PL) to allow for third party access.

3.2 Oil and Gas Act No. 49 of 1998

In 1998 an Act entitled “Oil and Gas Act 1998” was formally endorsed by the

National Parliament. This act is a comprehensive legislation governing the

exploration for and production of petroleum (including oil and gas) in Papua New

Guinea, including the offshore area, and the grant to traditional landowners and

provincial Governments and Local-level Governments of benefits arising from

projects for the production of petroleum (including oil and gas), and the processing

and transportation in Papua New Guinea of petroleum and petroleum products.

Part IV of the Act stipulates the conditions concerned to the state equity

entitlement and project benefits arising from such equity entitlement. Its Article 165

stipulates that the State has the right (but not obligation) to acquire, directly or

through a nominee, all or any part of a participating interest not exceeding 22.5%

in each petroleum project.

By this condition the right of landowners and provincial government in the affected

area by the execution of petroleum project are protected and benefits arising from

such project is granted by the Company who undertakes the execution and

operation of such project. However, when the State acquire any interest shall bear

the sunk costs of the vendor attributable to the vendor ’s interest in the petroleum

project, equal to the percentage participating interest in the petroleum project.


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The State participation into the major petroleum project operated under petroleum

agreement among equity holders are summarized in Table xxx below.

In most cases the nominee of the State is Mineral Resources Development

Company Limited (MRDC). The outline of MRDC is discussed in subsequent

section. MRDC is a state agency mandated to participate and manage every kind

of natural resource development ranging from gold mining, forest development,

petroleum project, etc. As for the natural gas development project, the other

government entity is formed and nominated to undertake the participating in the

gas project and manage the interest of provincial government and landowners

concerned to each project. Therefore, NGC is deemed as a corporate trustee of

that state interest. However, NGC has not exercising his right and authority to gas

project to date due to a lack of financial and managerial capability to undertake

such task.

AS to protect and gain the benefits from the execution of petroleum project by the

Provincial Government, the National Gas Corporation Limited (NGC) has been

formed. Section 179 of the Act stipulates the right and obligation of NGC

3.3 Mineral Resources Development Company Limited (MRDC)

In 2001, the State-owned Mineral Resources Development Company Limited

(MRDC) acted as the State nominee in the major resource projects and can

compulsorily acquire up to 30% in mining projects and 22.5% in petroleum

projects on behalf of the State. As it is government policy to provide equity for

landowners in major resources projects, a portion of State’s equity share is

reserved for this purpose. In mining projects it accounts for 5% of gross equity and

in petroleum project at 2%. In PNG almost 97% of the land is tribally owned and is

core to a way of life for people living in a village based subsistence economy.

These equities is allocated to landowners at no cost.

MRDC, by virtue of its nominee status on behalf of the State, has an important

mandate to manage landowner equity in the major resource projects on behalf of

landowners. It also manages the equity held by some provincial governments in

these projects. The landowners and provincial government equity is held in

companies controlled by boards of directors and managed by MRDC through

Trust arrangements. Currently MRDC manages a number of these companies


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including Petroleum Resources Kutubu Limited (PRK), Petroleum Resources

Gobe Limited (PRG), Mineral Resources Star Mountains Limited (MRSM), Mineral

Resources Enga Limited (MRE), and Mineral Resources Lihir Limited (MRL).

MRDC is entirely responsible for sourcing the finance to acquire landowner equity.

3.4 National Gas Corporation Limited (NGC)

The Oil and Gas Act 1998 introduced a provision for the setting up of a National

Oil Corporation Limited (NGC) by the Provincial Government in respect of future

gas projects in Papua New Guinea. The corporation was subsequently formed by

all 20 Provincial Government at the beginning of 1999. Although this company has

been registered by law and formally established it has not acting as a corporation

yet to date due to a lack of funding.


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4. Natural Gas Development Plans and Projects in PNG

4.1 PNG GTA ( Gas to Australia) PROJECT

4.1.1 General

The project is referred to as PNG to Queensland Gas Project. A project proposed

2,695 km, onshore/offshore pipeline project to transport gas from the Southern

Highlands in Papua New Guinea to Queensland, Australia. The estimated

development cost of this project is US$ 2.5 billion. LPG is planned to be separated

out for domestic and export markets at a coastal processing facility in the Gulf of

Papua before the dry gas is piped across the Torres Strait to Cape York and down

to Gladstone (north of Brisbane) in Queensland. The Australian section of the

pipeline is planned to be owned and operated by a consortium consisting

Australian Gas and Light (AGL) and Petronas of Malaysia, if the project

proceeds. The pipeline route of the project is as illustrated in Figure-4a.


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Figure-4a

Proposed PNG GTA (Gas to Australia) Project Pipeline Routes

Hides

Kikori

Offshore Processing Facilities


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4.1.2 Gas Reserves

The gas reserve size of the discovered gas fields in Papua New Guinea that

could be commercialized for the PNG to Queensland Gas Project is 8.4 TCF as

shown in Table- 4a. Of 8.4 TCF gas reserves, 5.9 TCF of sale gas would be

necessary to launch the project.

Table-4a Objective Gas Fields and Natural Gas Reserves

for PNG GTA Project Oil/Gas Fields Remaining Reserves (Tcf) Hides 6.000 Kutubu 1.100 Moran 0.235 Gobe Main 0.200 SE Gobe 0.100 Barikewa 0.390 SE Hedinia 0.150 SE Mananda 0.200 Total 8.375

4.1.3 Processing Facilities

The facility proposed was to remove the propane and butane from the gas stream

for processing to LPG. The LPG will then be stored at the facility prior to shipping to

export and domestic markets. Possible options considered for the processing

facility included the use of and FPSO before the project group decided on the use

of a concrete gravity structure for the proposed facility.

4.1.4 Pipelines

On shore capacity of the PNG section of the pipeline is estimated to be around 400

mmcfd initially. It is anticipated that the offshore section will have a capacity of

around 700 mmcfd. The schedule of pipeline length and diameter for each section

is as summarized in Table-4b.

Table-4b Pipeline Routes, Sizes and Lengths in PNG GTA Projects Starting

Point/Destination Length

(km) Diameter (inches)

Hides to Kutubu 68 22 Kutubu to Kikori 189 22


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Kikori to Offshore Processing Facilities

76 26

（Sub-total） (333) Offshore Processing Facilities to Cable Beach

403 24

Cable Beach to Townsville

1,278 24

Townsville Lateral 71 18 Townsville to Gladstone 678 18 Gladstone to Brisbane 460 18

(Sub-total) (2,890) Total 3,223

4.1.5 Capital Investment Costs

The operator of the project, Chevron in 1998, has estimated that the overall cost of

the project will be around US$ 3.5 billions. A breakdown of costs is shown in

Table -4.c.

Table –4c Capital Investment Costs of PNG GTA Project Section Estimated Cost

(US$ million) PDL 1 (Hides) Development 700 PDL 2 (Kotubu Field Complex) and 4 (Gobe) Development

300

Wet Gas Pipeline (PNG onshore/offshore) 400 Marine Processing Facility 500 Dry Gas Pipeline (PNG Offshore) 200 Dry Gas Pipeline (Australia onshore/offshore) 1,400 Total 3,500

Currently the cost of this project is estimated to be around US$ 7,000 millions.

4.1.6 Present Situation as of August 2004

Although around 10 years has passed since the inception of the project

development plan, even a preliminary gas sale contract has not been completed

satisfactory in Australia relevant to this project. The ownership of gas pipelines

has not been determined definitely in PNG and the fund arrangement process has

not been proceeded properly in PNG as well. Under such situation, the

implementation of this project has almost been suspended in both countries.


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4.2 Alternative Proposed Plans and Projects relating to Natural Gas

Development and Utilization

At present no definite alternative project for commercialization of reserved gas has

been prepared or presented to the Government of Papua New Guinea for its

consideration.

Several alternatives can be thought such as to produce methanol, DME, or GTL.

Among these alternatives to produce and to export GTL in a form of crude is

thought to be the best alternative since the variety of products produced based on

GTL crude is the largest among others thus the marketing of products could be

easier than the others and minimize the risk to limit the type of importer or users.

The outline of the proposed plans and projects are summarized in Table-4d.


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Table-4d

Alternative Plans and Projects relating to Natural Gas Development and its Utilization In

Papua New Guinea (PNG) No. Name/Title

of Plans or Projects

Proposed in year

Planned/ proposed

by

Products and main facilities’

description

Plant sites and

markets

CAPEX (MMUS$

) and others

Remarks (For more

details, refer to

Collected Data and

Information in

Appendices)

1. Gas-to-Electricity (GTE) Project

Under operation

Fuel gas for power generation

Under operation to be supplied to mines

2. Highlands Gas Project

2004 Oil Search

Maximum gas production: 650 MMscd as fuel gas, raw materials for CNG and methanol plants, etc., Pipelines from Highlands to Port Moresby and Gladstone, Australia

PNG, Australia, New Zealand

US$7,000MM, Oil search will carry out the FEED at the cost between US$ 60MM and US$70MM.

Page 14 of Ref. No. of 6.4

3. Integrated Methane Complex Project

July, 2003

ITL/ Rentech, Indonesia

LNG: 3 MMt/y Natural gas input: 300 MMscfd

Northern PNG

US$750MM

4. Ditto. Ditto. Ditto. GTL →Ammonia: 2.41 MMt/y , Urea: 0.837MMt/y, Methanol: 0.66 MMt/y, Natural gas input: 300 MMscfd

Ditto. US$1,650MM

5. Ditto. Ditto. GTL: 16,500 bpd

US$525MM

6. Ditto. Ditto. Methanol: 1,200 t/d

US$82MM

7. Methanol/DME

June, 2003

Mistubishi Gas

Methanol: 4,000-7,000 t/d

Napa Napa

US$500 -


23

No. Name/Title of Plans or

Projects

Proposed in year

Planned/ proposed

by


description

Plant sites and

markets

CAPEX (MMUS$

) and others

Remarks (For more

details, refer to

Collected Data and

Information in

Appendices)

Project Chemical (MGC), and Itochu

→ DME: 2,800-5,000 t/d, Required natural gas: 160 –280 MMscfd

or Kerema in PNG

600MM

8. GTQ (Gas to Queensland) Project

1998 Chevron Asiatic, BHP Petroleum (Australia), Mitsubishi Oil, Mobil Exxon and Production, Oil Search, Oregon Mineral (Kutubu), and Petroleum Resources Kutubu

LPG, Condensate, and Natural gas: 300/ 390/800 MMscfd, Pipelines: Kutubu-Kopi/Kopi – River entry/River entry- CGS: 22” φ /26” φ/26” φ x 273km in total. Pipelines: 26”φ-24”φ-12”φ-22” φ x 2,356km in total (CGS in the Gulf of Papua to Gladstone, Australia), Pressure rating of pipeline: 900#

PNG, Australia

US$3,400MM = US$2,100 MM (in PNG territory )+US$1,300MM (in Australian territory),

Ref. No. of 2.8

9. LNG Project

1995/1996

BP/Exxon

LNG: 3.4 MMt/y, Required natural gas: 510 MMscfd（Estimated）

Northern PNG

US$3,160MM including wells and pipelines (26” φ x 375 km, 900#

Appendix A2 of Ref. No. of 2.8


24

No. Name/Title of Plans or

Projects

Proposed in year

Planned/ proposed

by


description

Plant sites and

markets

CAPEX (MMUS$

) and others

Remarks (For more

details, refer to

Collected Data and

Information in

Appendices)

from Hides to Wewak)

Notes: 1) MM = 1,000 x 1,000 = 1,000,000 (Million), 2) CGS: Concrete Gravity Structure, 2) FEED: Front End Engineering and Design


25

5. Gas-to-Liquid (GTL) Process and Technologies

5.1 General

GTL is a process for converting natural gas into synthetic oil, which can then be

further processed into fuels and other hydrocarbon-based products. In the

simplest of terms, the GTL process tears natural gas molecules apart and

reassembles them into longer chain molecules, like those that comprise crude oil.

However, with this particular conversion process, the result is an extremely pure,

synthetic crude oil that is virtually free of contaminants such as sulfur, aromatics

and metals. This synthetic crude can then be refined into products such as diesel

fuel, naphtha, wax and other liquid petroleum or specialty products.

Table-5a shows GTL manufacturing existing/planned plans and projects in the

world.


26

Figure-5a

GTL Manufacturing Plans and Projects in the World

(Legends)

： Existing plant

： Under F/S (Feasibility Study)

： Planned


27

5.2 GTL Crude (Syrhcrude)

GTL crude is more environmental-friendly than other crude oil as shown on

Table-5a.

Table- 5a Diesel Fuel Specifications

Property Current Crude Oil Diesel Fuel

2006 Diesel Requirement in USA

GTL Diesel Fuel

Sulfur Content (ppm)

500 15 Zero

Aromatics (%) 30 30 Zero Cetane Index 45 45 >74

5.3 GTL Process and Technologies

The GTL process is based on the following two (2) primary steps:

1) The conversion of natural gas into synthesis gas - In the first step in the

process, natural gas is reacted with oxygen in certain patented process using

proprietary catalytic partial oxidation to produce synthesis gas, consisting

primarily of carbon monoxide and hydrogen.

2) The conversion of synthesis gas into synthetic crude - In a reaction

based on proprietary catalyst, converting it into hydrocarbons. FT

(Fischer-Tropsch) chemistry reaction: The synthesis gas flows into a reactor

containing catalysts of Fe, Co, Ru, etc..

Schematic flow diagram of the GTL manufacturing is as shown in Figure-5b.

Table-5b summarizes the process and technologies in the world.


28

5.4 Significant Benefits of GTL

A number of significant benefits of GTL is as follow.

1) Monetizing Stranded Natural Gas Reserves: The world's proved and

potential natural gas reserves are estimated to be more than 14,000 trillion

cubic feet (TCF). Most of these reserves are considered stranded because

they are too far from the consumers and difficult to transport. The case of

PNG’s gas is a typical stranded gas. GTL has the potential to convert a

significant percentage of this gas into several hundred billion barrels of liquid

petroleum - enough to supply the world’s energy needs for the next 25 years.

GTL offers tremendous economic value to the countries and/or companies

that control these reserves. GTL will permit the economic development of

these remote natural gas discoveries that currently are deemed too far from

market to be of economic value.

2) GTL Fuel Contains No Sulfur: GTL fuels, such as ultra-clean diesel,

contain non-detectable levels of sulfur, metals and aromatics. Diesel engines

perform more efficiently on synthetic fuels because of the extra power from a

higher cetane index and the elimination of contaminants that attack

emission-reducing equipment. As a product, GTL fuels surpass new rules of

Japan, the United States, and Europe that require refineries to reduce the

sulfur content of present-day diesel fuel by 97% or so, to 15 ppm or 10 ppm,

over the next several years. Such regulations are providing the impetus to the

introduction of new, green, designer fuels to a much wider market.

3) Compliance with Clean Air Standards: Since GTL diesel already

exceeds the new worldwide specifications for low-sulfur diesel fuel, it will be

in demand for blending with conventional diesel to satisfy increasingly

stringent clean-air standards. The auto industry has rapidly developed new

engine technologies that, with GTL fuels, can meet clean-air standards --

giving green fuels a clear economic advantage. Stripping sulfur out of

traditional crude-oil products is prohibitively expensive.


29

Table-5b GTL Process and Technologies in the World Company Process

Name Synthetic Gas

Process FT Synthesis

Process References Remarks

Shell SMDS POX Temperature: 1,200-1,500℃, Pressure: 2-85 bar Catalyst:: Not required

Catalyst: Co 12,500 bpd (Commercial)

Capacity of plant:: 30,000 bpd and larger.

Sasol (South Africa)

SSPD ATR Reaction temp. & press.: 800℃, 20 bar Catalyst:: Ni

Catalyst: Co 2,500 bpd (Semi-commercial)

Ditto.

Exxon Mobil

AGC-21 ATR Reaction temp. & press.: 800℃, 20 bar Catalyst:: Ni

Catalyst: Co 200 bpd (Pilot test)

Ditto.

Rentech

--- Catalyst: Fe 250 bpd (Pilot test)

Capacity of plant: 10,000 bpd and smaller

Sytroleum (USA)

--- ATR Reaction temp. & press.: 800℃, 20 bar Catalyst:: Ni

Catalyst: Co 70 bpd (Pilot test)

Ditto.

BP Under research and development

Conoco Ditto. JNOC (Japan)

JNOC-GTL

CO2 /Steam reforming : Utilize CO2 in natural gas, Reaction temp. & press.: ,880℃, 21 bar

10 bpd (Pilot test), 5,000 bpd in Indonesia (Feasibility study with PERTANINA)

The JNOC-GTL process does not need: - CO2 removal - Costly oxygen generator - Syngas conditioning

Japan DME (Japan)

JFE New Process

DME direct synthesis: CO2 /H2 → DME

100 ton (DME)/d (Pilot test planned)

2,500 ton (DME) and (Target capacity of commercial plant) Conventional process (Indirect


30

Company Process Name

Synthetic Gas Process

FT Synthesis Process

References Remarks

synthesis): Natural gas →Methanol → Dehydration → DME

Notes: 1) SMDS: Shell Middle Distillate Synthesis, 2) SSPD: Sasol Slurry Phase Distillate, 3) AGC-21: Advanced Gas Conversion for the 21 Century, 4) JNOC: Japan National Oil Corporation


31

6. Outline of the Win-Win Project for PNG and Japan

This section describes the design conditions of plants and facilities and briefs outlines of the

win-win project for PNG and Japan.

6.1 Natural and Environmental Conditions at Proposed Sites

Natural conditions relating to plan and design of plants and facilities are shown in

Tables-6a, and -6b and Figure-6a. However, the further detailed survey and

investigation shall be carried out in the stage of more detailed engineering and design.

Table-6a

Natural Conditions (Climate and Sea Conditions) in Southern Highlands and Gulf of Papua

Lake Kotubu

Gobe 450 km north-west of Port

Moresby

Kikori Kikori Delta, Nerashore or

Offshore Altitude 1000m 1000m 50 m Water depth Atmospheric temperature (Mean monthly)

22 – 24℃ 22 – 24℃

Atmospheric temperature (Lowest recorded)

4℃ 4℃

Humidity (Mean monthly)

70-90% 70-90%

Rain (Annual average

4,500 mm 3,500 – 4,500 mm 5,700mm

Rain (Mean monthly)

300 (Nov. - Feb.) -

700(May - June)

Winds, Offshore Kikori Delta

--- --- --- Northwest monsoon (December to March), Southeast trades (May to October), and transitional seasons. Prevailing wind direction: Northwest monsoon

Current recorded, Nearshore Kikori

-- --- --- Strong flood and ebb tidal current::


32

Delta 1.8 m/s in the channel of Kikori Delta

Source: a) “Kutubu Petroleum Development Project - Environmental Plan,” Prepared by NSR Environmental Consultants Pty. Ltd.（Australia）, March 1, 1990, b) “Kopi 30,000 b/d Refinery – Environmental Plan”, Prepared by LeProvost Dames & Moore (Perth, Australia), May 27, 1994

Table-6b

Tidal Level referred to Datum of Sounding in Gulf of Papua Lat Log Heights in meters (m) above datum S E MHWL MHWS MSL MLWN MLWS

Remarks

Kikori 7°25 ’

144°15’

2.3 1.6 1.2 0.9 0.1

Goaribari Island

7°45 ’

144°12’

4.4 3.1 2.8 2.4 1.1 Island between Kikori River and Omali River

Kumul (Water depth = 20 m)

Offshore Kikori Delta (Gulf of Papua)

Source: Chart – Papua New Guinea South Coast, Scale = 1/300,000, March 22, 1974, Australian Hydrographic Service


33

6.2 Reservoir Fluid Analysis Reservoir pressures and Recoverable Reserves

Reservoir fluid of Hides Gas Field, which has the largest reserves in PNG, is as

shown on Table-6c.

Table-6c Reservoir Fluid Analysis

(Hides Wells #1, 2, 3 & 4） Component Mole %

CH3 85.80 - 90.29 C2H6 7.96 – 8.22 C3H8 1.97 – 3.00 i-C4H10 0.08 – 0.53 n-C4H10 0.24 – 0.58 i-C5H12 0 - 0.16 n-C5H12 0 - 0.37 C6 0 - 1.55 CO2 0 - 0.37 N2 0 - 1.96

Recoverable reserves of natural gas in PNG in 2003, 2001, 2000, and 1997 are as

shown on Tables-6d, -6e, -6f and -6g respectively. The tables also show initial

reservoir pressures in some reservoirs. As a total recoverable reserve of natural

gas in PNG, 14 to 15 Tcf of natural gas would be expected.


34

Table-6d. Gas Reserves of Main Fields in Papua New Guinea (PNG)

(2003 Annual Report on Petroleum Activity in Papua New Guinea – December 2003) Field Name Gas Condensate Initial

Reservoir Pressure

Remarks

Original GIP1)

2P2) Recoverable

2P2) Recoverable

(Tcf) (Tcf) (MMstb) (MPa) (Onshore) P’nyang 2.489 1.078 9.10 Ketu 0.544 0.017 0.10 Elevala 0.611 0.423 2.50 30.1 Stanley Juha 1.541 0.452 19.20 Hides 9.584 6.700 101.00 38.1 Angore 9.034 4.089 6.10 48.6 Moran (Gas) 0.654 0.197 66.09 Crude oil is

being produced. SE Mandana

(Gas) 0.301 0.000 0 Crude oil is also

reserved. Paua Agogo Agogo

Production Facilities (APF)

Iagifu-Hedinia 26.9-27.6 Kutubu CFP Central Processing Facility (Capacity 130,000 bpd)

SE Hedinia 0.209 0.157 0 Kutubu (Gas) 1.958 1.366 31.10 Crude oil is

being produced. Gobe Main

(Gas) 0.708 0.476 27.79 Crude oil is

being produced. Makas SE Gobe (Gas) 16.1 Crude oil is

being produced. Iehi 0.104 0.011 0 Koko Kimu --- --- --- Kuru 0.084 --- 0 Bwata 0.092 0.040 0 Barikewa 0.121 0.069 0 Uramu 0.137 0.032 0 Puri 21.7 (Offshore) Pasca 0.610 --- 0 Pandora 1.738 0.513 0 (Total) 30.519 16.241 283.18 Notes: 1) GIP: Gas in Place, 2) Proved (P), Proved + Probable (2P), Proved + Probable + Possible (3P)


35

Table-6e Gas Reserves of Main Fields in Papua New Guinea (PNG)

(As of January, 2001) Field Name Gas Condensate Initial

Reservoir Pressure

Remarks

Original GIP1)

2P2) Recoverable

(Tcf) (Tcf) (MMstb) (MPa) (Onshore) P’nyang 1.800 16 Ketu 0.450 31 Elevala 0.550 37 30.1 Stanley 0.010 10 Juha 1.300 55 Hides 5.000 115 38.1 Angore 0.900 12 48.6 Moran (Gas) Crude oil is

being produced. SE Mandana

(Gas) 0.200 20 Crude oil is also

reserved. Paua 0.000 20 Agogo Agogo

Production Facilities (APF)

Iagifu-Hedinia 26.9-27.6 Kutubu CFP Central Processing Facility (Capacity 130,000 bpd)

SE Hedinia 0.150 3 Kutubu (Gas) 1.100 0 Crude oil is

being produced. Gobe Main

(Gas) 0.200 0 Crude oil is

being produced. Makas 0 10 SE Gobe (Gas) 0.100 0 16.1 Crude oil is

being produced. Iehi 0.030 0 Koko 0.010 10 Kimu 0.050 0 Kuru 0.225 0 Bwata 0.050 0 Barikewa 0.390 0 Uramu 0.120 0 Puri 0 1 21.7 (Offshore) Pasca 0.225 25 Pandora 1.600 0 (Total) 14.460 360 Notes: 1) GIP: Gas in Place, 2) Proved (P), Proved + Probable (2P), Proved + Probable + Possible (3P)


36

Table-6f Gas Reserves of Main Fields in Papua New Guinea (PNG)

（As of May, 2000） Field Gas Condensate Initial

Reservoir Pressure

Remarks

Original GIP1)

2P2) Recoverable

(Tcf) (Tcf) (MMstb) (MPa) (Onshore) P’nyang 0.555 0.416 3 Ketu 0.023 0.017 0 Elevala 0.140 0.110 1 30.1 Stanley (Not tested) Juha 1.000 0.750 30 Hides 10.000 8.000 272 38.1 Angore 4.500 3.600 15 48.6 Moran (Gas) 0.556 0.202 Crude oil is

being produced. SE Mandana (Gas) 0.301 0.226 0 Crude oil is also

reserved. Paua Agogo (0.049) (900) Iagifu-Hedinia (1.500) 26.9-27.6 SE Hedinia 0.209 0.157 0 Kutubu (Gas) 1.951 1.361 0 Crude oil is

being produced. Gobe Main (Gas) 0.298 0.217 0 Crude oil is

being produced. Makas SE Gobe (Gas) 0.414 0.267 0 16.1 Crude oil is

being produced. Iehi 0.060 0.030 0 Koko Kimu 0.400 0.300 Kuru (0.086) Bwata 0.074 0.041 0 Barikewa 0.120 0.069 0 Uramu 0.203 0.122 0 Puri 21.7 (Offshore) Pasca Pandora 1.400 1.000 0 (Total) 22.204 16.885

(1.568) 321

(900)

Notes: 1) GIP: Gas in Place, 2) Proved (P), Proved + Probable (2P), Proved + Probable + Possible (3P)


37

Table-6g

Gas Reserves of Main Fields in Papua New Guinea (PNG) （Analyzed by Worley Limited, Australia and updated by Chevron and BP in

September, 1997） Field Gas Condensate Initial

Reservoir Pressure

Remarks

Original GIP1)

2P2) Recoverable

(Tcf) (Tcf) (MMstb) (MPa) (Onshore) P’nyang 0.42 Ketu 0.02 Elevala 0.11 30.1 Stanley Juha 0.66 Hides 4.60 38.1 Angore 0.90 48.6 Moran (Gas) 0.22 Crude oil is

being produced. SE Mandana (Gas) 0.18 Crude oil is also

reserved. Paua Agogo Iagifu-Hedinia 26.9-27.6 SE Hedinia 0.11 Kutubu (Gas) 1.38 Crude oil is

being produced. Gobe Main (Gas) 0.27 Crude oil is

being produced. Makas SE Gobe (Gas) Included in

Gobe Main 16.1 Crude oil is

being produced. Iehi 0.03 Koko Kimu Kuru 0.00 Bwata 0.04 Barikewa 0.07 Uramu 0.03 Puri 21.7 (Offshore) Pasca 0.00 Pandora 1.00 Others 0.30 (Total) 10.04 Notes: 1) GIP: Gas in Place, 2) Proved (P), Proved + Probable (2P), Proved + Probable + Possible (3P)


38

6.3 Natural Gas Processing, Gathering and Transportation System

Natural gas produced at fields will be dehydrated at fields to prevent from formation

of gas hydrates in pipelines and separated into dry gas and condensate. The dry

gas and condensate will be transported through to individual transmission pipelines

to FPSP where GTL manufacturing plants will be installed (See Figure-6b.).

6.4 Design Capacities of Pipelines and GTL Plants

Based on recoverable reserves of Papuan Basin in western PNG, the realistic

capacities of pipelines and plants will be as shown on Table-6h.

Table-6h Design Capacity of Pipelines and GTL Manufacturing Plants

Case Natural Gas (Dry

gas) MMscf/d

Condensate (NGL)

b/d

GTL Crude

b/d

LNG MM t/y

(Only for reference)

SPM + FPSO M dwt

Remarks

1 1,200 33,600 120,000 8.00 260 2 900

(36”φ) 25,200→

30,000 (12”φ)

90,000 6.00 200 Maximum design capacity applied in the project.

3 600 (30”φ)

16,800→20,000 (10”φ)

60,000 4.00 140

4 300 (24”φ)

8,400→ 10,000 (8”φ)

30,000 2.00 80

Notes : 1) GOR = 22 - 34 – 52 stb/MMcf, 2) Delivery pressure to GTL plants: 2 Mpa, 3) Maximum design pressure of dry gas pipeline: 1,440 psig, Operating pressure: 720 - 1,440 psig, 4) Maximum design pressure of oil pipeline: 275 psig, 5) GTL yield: 10,000 bbl of GTL/MMscf of Natural Gas, 6) LNG yield: 500 MMscf/d x 20 t/MMscf x 330 operation days/year x = 3,3 00,000 tons/y = 3.3 MM tons/y (LNG)

Figure-6c shows the proposed plants and facilities in case of natural gas of 900

MMscfd of natural gas including existing oil handling facilities.


39

Angore

Hendinia/ Iagifu

Hides

Juha

Gobe Main

SE Gobe

Barikewa

Pandora

FPSO

Figure-6b Gas and Condensate Transmission Plan and Concept

(Legends)

Dry Gas

Line

Condensate Line

Main Gas Fields

(Gulf of Papua)

(Southern Highlands)


40

6.5 Project Schedule and Capital investment

The earliest and rapidest project schedule will be as shown on Table-6 j.

GLT plant is considerably expensive at present. The order of magnitude cost

estimate will range between US$ 1,200 millions and US$ 2,500 millions as shown

on Table-6 i, considerably varying on number of trains of GTL manufacturing

plans.

Upstream facilities such as gas wells, flowlines, gas dehydration plants and ties-in

to transmission lines shall be provided by field operators and/or gas producers at

their expenses.

Table-6 i

Capital Investment Costs Plants and Facilities Size/Capacity Quantity Amount

MMUS$ Dry gas transmission lines to FPSO

36 Inches diameter

330 km 453

Condensate transmission line to FPSO

12 Inches diameter

330 km 151

PLEM + SPM 200,000 dwt 1 set 15 FPSO Hull 200,000 dwt 1 ship 50 GTL Plants 30,000 bpd 1/2/3

trains 600/1,200/1,800

Total 1,265/1,875/2,465


41

6.6 Project Operation and Operational Entities

Figure-6d shows the ideal organization and operational entities which proceed and

execute the project.

The field operators and gas producers had better be Oil Search, Exxon-Mobil,

Chevron, etc. who hold prospecting and/or developing licenses in Papuan Basin,

PNG and well know data and information on reservoirs in natural gas fields.


42

Notes: ① Long contract on sales of natural gas and condensate between pipeline operators and/or GTL Manufacturing plant operators and each oil & gas field operators/producers had better be made. ② Syncrude and condensate (NGL)

Figure-6d

Project Executing Organizations and Operation Companies (Draft)

Oil & Gas FieldOperator/ Producer

Pipeline Operator (i.e. PNG governmental agencies (NGC, MRDC,

EDA Gas, etc) + oil refining firms)

GTL Manufacturing Plant Operator

(i.e. oil refining firms and/or shipbuilding firms)

Domestic refineries in

PNG

②

①

China Japan

Taiwan Korea

Philippines

②

Overseas refineries



①

①


43

7. Conclusion and Recommendation

Since the big natural gas fields of Hides were found in the Southern Highlands Province,

a number of natural development plans and projects have been proposed to PNG by

USA, Australia, Indonesia, Japan, etc.. However, most of plans and projects are not

attractive and favorable to PNG to be frozen until now.

To realize the project which is beneficial for PNG and Japan, the full-scale feasibility

study (F/S) shall be carried out together by Japanese enterprises who eagerly desire to

financially, technically and operationally participate in oil & gas field development in PNG.

At first, the following survey, negotiation, etc. shall be done in the F/S:

(1) Detailed site survey and field reconnaissance by Japanese enterprises who

desire to financially and/or technically participate in natural gas development in

PNG (i.e. operation of natural gas fields, pipelines, LNG manufacturing plants on

FPSO, etc.).

(2) Collection of detailed data and information on oil and gas reserves and

prediction of their productions, reservoir pressures, wellhead pressures and

temperatures, fluid properties, etc.. .

(3) Detailed discussion and negotiation on framework of natural gas field

development and financial and technical participation by Japanese enterprises

with the following stakeholders:

- PNG Government, authorities, and agencies such as National Gas

Corporation (NGC), EDA Gas, Ministry of Petroleum of Petroleum and Energy,

Mineral Resources Development Company (MRDC), etc.);

- Existing oil & gas field operators/licensers in PNG such as Exxon-Mobil,

Chevron, Oil Search Ltd., as a representative of PNG’s sate, etc.

(4) Preparation and signing of mutual contracts, agreements and/or


44

understandings among the above-mentioned stakeholders (i.e. Long-term sales and

supply of natural gas, etc.)

As Japanese enterprises who participate in the project, the following enterprises or their

consortium/joint venture will be recommended:

- Trading firms,

- Oil & gas field development companies,

- Oil refineries,

- Shipbuilders, etc.

For reference, the table of contents which should be minimally studied in the subsequent

full-scale F/S the are shown on Table-7.a.


45

Table-7.a

Table of Contents for Full-scale Feasibility Study

on Natural Gas Development and GTL Manufacturing plans

in Papua New Guinea Section

Description Remarks

Table of Contents Executive Summary Abbreviation and Terminologies

1. DEMANDS AND MARKETS OF NATURAL GAS

AND ITS PRODUCTS IN THE WORLD AND JAPAN

2.1 Trends In the world 2.2 Trends In Japan 2. Natural Gas Development Laws, Rules and

Regulations in PNG

2.1 Oil and Gas Acts in PNG 2.2 Foreign Investors, Investments and Taxation 3.

SELECTED AND PROPOSED PLANS AND DESIGN OF PLANTS AND FACILITIES

3.1 Design Bases and Conditions 3.1.1 Natural and Environmental conditions 3.1.2 Reserves of oil and gas and production data and

information (fluid analysis, pressure, temperature, etc.)

3.2 Plans and Design of Pipelines, Plants, and Facilities

3.2.1 Gas Hydrates and Dehydration Processes 3.2.2 Natural Gas Gathering and Transportation System 3.2.3 GTL Manufacturing Process and Plants* Including selection of GTL

manufacturing process and preparation of quotation specification for EPC&I of GTL manufacturing plants

3.2.4 PLEM, SPM and FPSO * 3.2.5 Others – Infrastructures, logistics, etc. 3.3 Overall Project Schedules from FEED to Start of

Operation

3.4 CAPEX and OPEX of the Project

4. ENVIRONMENTAL CONSIDERATION AND INITIAL

ENVIRONMENTAL EXAMINATION (IEE)

4.1 Environmental Laws, Rules and Regulations in PNG 4.2 Initial Environmental Examination (IEE)


46

Section

Description Remarks

4.3 Terms of Reference (TOR) of Full-scale EIA and its Budget

4.4 Clean Development Mechanism (CDM) and Potential Renewable Energies in PNG

5. FINANCIAL PLANS AND ECONOMIC ANALYSIS ** 5.1 Basis of Analysis 5.2 Financial Plans and Resources, and Loan Schemes 5.3 Economic Analysis 6. CONCLUSION AND RECOMMENDATION APPENDICS

Notes: 1) * Includes selection of GTL manufacturing process and preparation of quotation

spec


47

Appendices

Appendix (1): Tables & Figures (Size: A3) Appendix (2): Site Survey Itinerary (August 23 to September 4,

2004) Appendix (3): Photos in Site Survey and Investigation


48

Appendix (1)

Figures and Tables (Size: A3)


49

List of Figures and Tables

No. Title Figure-1a : Geographic Map - Overall Papua New Guinea (PNG) Figure-1b : Geographic Map – Bismarck Sea- Wewak-Soutern Highlands-Kikori

Delta-Gulf of Papua Figure-2b : PNG Oil & Gas Field Concession Map (1) Figure-2c : PNG Oil & Gas Field Concession Map (2) Figure-5b : GTL Manufacturing Process (Typical) Figure-6a : Bathymetric Map (Chart) – Western Gulf of Papua Figure-6c : Natural Gas Development and GTL Manufacturing Plan and Concept Table-6 j : Earliest and Rapidest Project Schedule (Draft)

(See Figure -1b.)

Figure-1a

Geographic Map – Overall Papua New

Guinea (PNG)

Port Moresby

Lae

Medung

Wewak

Kikori

Rabaul

Vanimo

Papuan Basin

Figure-1b

Geographical Map

– Bismark Sea – Wewak – Southern Highlands– Kikori Delta - Gulf of Papua

Kik

ori

Kop

i

Hid

es

Mor

an

Kum

ul O

il Te

rmin

al

Gob

e

Wew

ak

6°00

’ 00”

S

8°00

’ 00”

S

4°00

’ 00”

S

142°

00’ 0

0” E

14

4°00

’ 00”

E

Men

di

Pap

uan

Bas

in

Figure-2b

PNG Oil & Gas Concession Map (1)

Figure-2c

PNG Oil & Gas Field Concession Map (2)

Natural Gas CO2

Removal

Sulfur Removal

Synthetic Gas Production

Process (SR/ POX/

ATR)


Oxidants (O2(Air), H2O(Steam), CO2, etc.)

Distillation

Hydro- cracking

Synthetic Crude

Naphtha

Synthetic Gas(CO and H2）

H2

Gas Oil

Kerosene

H2

Figure-5b

GTL Manufacturing Process (Typical )

Fe, Co, Ru, etc.

(Domestic and overseas Oil Refineries)

Notes: 1) SR: Steam Reforming 2) POX: Partial Oxidation 3) ATR: Automatic Thermal Reforming

Ni

Wax, etc

（FPSO）

Kumul Oil Terminal and SPM

Capacity: 60,000 to 150,000 dwt

Figure-6a

Bathymetric Map (Chart) – Western

Gulf of Papua

Makari River

Kikori River

Turama River

Kikori

Kutubu Oil Field and

Central Production

Facilities (CPF)

Hides

Gas Field

SPM + FPSO (200,000 dwt Class)

36”φx 330 km - Dry Gas Transmission Line

12”φx 330km - NGL Transmission Line

Kumulu Oil Terminal +

SPM, Capacity:

60,000 to 150,000 dwt

20”φx 270 km Crude Oil

Export Line, Capacity:

200,000 b/d

Figure-6c Natural Gas Development and GTL

Manufacturing Plan and Concept (Draft)

P’nyang

GTL Plant of 30,000bpd

(Future)

(Future)

(Gulf of Papua)

(Province of Southern Highlands)

(Province of Gulf)

Pandora

Gas Field

Angnore Juha

Kutubu

（Legends & Notes）

： Dry Gas Line (Proposed)

: NGL Line (Proposed)

: Plants & Facilities (Existing)

: Main Gas Fields

Notes: 1) Natural gas will be dehydrated and separated into dry gas and condensate (NGL: Natural Gas Liquid) within fields.

2) Start of Kutubu crude oil production: 1992.

Gobe Oil Field

Moran Oil Field

1 2 3 4 1 2 4 1 2 3 4 1 2 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4

Natural gas production (MMscfd/d)GTL crude production (Mbbl/d)Condensate/NGL (Mbbl/d)

1 Feasibility Study (F/S)

2 Front-End Engineering and Design (FEED)

3 Bidding, bid evaluation and award of EPC&I contracts

4 Engineering, procurement, construction & installation (EPC & I)

4.1 Upstream facilities4.1.1 Wells4.1.2 Flowlines4.1.3 Gas Dehydration Plants4.1.4 Tie-ins to Transmission Lines?

4.2 Downstream facilities4.2.1 Dry Gas Transmission Line, 36 inches x 330 km4.2.2 NGL Transmission Line, 12 inches x 330 km4.2.3 PLEM + SPM4.2.4 FPSO (Floating, production, storage & offloading ) Hull, 200,000 DWT Second-handed tanker4.2.5 GTL Plants, 1 st train of 30,000 b/d4.2.6 GTL Plants, 2 nd train of 30,000 b/d4.2.7 GTL Plants, 3rd train of 30,000 b/d

5 Pre-commissioning and comissining

6 Start-up of plant operation ★ ★ ★

(Legends): Project management services?

: Field construction and installation: Prefabrication/assembly in shops and/or shipyards: Procurement of materials and equipment

(Draft)

10 11 122015

To be provided by fieldoperators/gas producersat their expenses

90

Earliest and Rapidest Project Schedule

1 2 3 4 92008 2009 2010 2011

5 6 7 82004 2005 2006 2007

60000

00 900 900 9000 300 300 600 600

10 10 200 0 0 0 30 30 60

30 30 30 3090 90

2012 2013 2014ItemNo.

Table-6 j

Year

RemarksEvents/Activities

0 0 0 0 0


50

Appendix (2)

Site Survey Itinerary (August 23 to September 4, 2004)


51

Site Survey Itinerary No. of

Day

Date Events and Activities Stay at

Remark

1 Aug. 23, 2004

Mon. Narita – Cairns (JL5141)

By air

2 Aug. 24 Tue. Cairns – Port Moresby (POM) (PX09)

By air

POM POM: Port Moresby

3 Aug. 25 Wed. Meeting with staffs of the relevant organizations of NGC and MRDC

POM NGC: National Gas Corporation MRDC: Mineral Resources Development Corporation

4 Aug. 26 Thu. Meeting with staffs of the relevant organization of NGC and MRDC

POM

5 Aug. 27 Fri. Meeting with staffs of relevant organization of NGC and MRDC

POM

6 Aug. 28 Sat. Meeting with a staff of DOPE and data filing of collected data and information

POM DOPE: Department (or Ministry) of Petroleum and Energy

7 Aug. 29 Sun. Data filling of collected data and information

POM

8 Aug. 30 Mon. Meeting with the chairman of NGC

POM

9 Aug. 31 Tue. Arrangement of field survey trip and reservation of chartered flight

POM

10 Sept. 01 Wed. Meeting with staffs of NGC and MRDC on field survey trip

POM

11 Sept. 02 Thu. Field survey trip: POM – Kikori - POM (Chartered flight of Air Niugini)

By air

POM

12 Sept. 03 Fri. Visiting at a DOPE office

POM

13 Sept. 04 Sat. Port Moresby – Cairns – Narita (PX090 - JL5142)

By Japan


52

Appendix (3)

Photos in Site Survey and Investigation


53

List of Photos

No. Title

Photo-1 : Chartered airplane at Port Moresby Jachsons International Airport

(Date: September 2, 2004) Photo-2 : Port Moresby Harbor (Date: September 2, 2004) Photo-3 : Napa Napa Oil refinery in Port Moresby Harbor (Date: September 2,

2004) Photo-4 : Kikori Delta (Date: September 2, 2004) Photo-5 : Kikori Delta (Date: September 2, 2004) Photo-6 : Existing pipeline launching point into the river (Date: September 2,

2004) Photo-7 : Signpost of buried pipeline (Date: September 2, 2004) Photo-8 : Old scrapped pipes of 20 inches in Kikori Village (Date: September 2,

2004)


54

Port Moresby Harbor

Napa Napa Oil Refinery

Photo-1: Chartered airplaneat Port Moresby Jacksons International Airort(Date: September 2, 2004)

Photo-2: Port Moresby Harbor (Date: September 2, 2004)


55

Photo-4：

Kikori Delta (Date: September 2, 2004)

Napa Napa Oil Refinery

Photo-3:

Napa Napa Oil Refinery in Port Moresby Harbor(Date: September 2, 2004)


56

Pipeline launching point to Kikori River

Photo-5:

Kikori Delta (Date: September 2, 2004)

Photo-6: Existing pipelinelaunching point into the river:Pipe of 20 inches launches intoKikori River and heading to Kumul oil terminal in Gulf of Papua (Date: September 2, 2004)


57

Signpost of pipeline

Photo-7: Signpost of buried pipeline: The pipeline of 20 inches is buried under the bottom of river (Date: September 2, 2004)

Photo-8:

Old scraped pipe of 20 inches in Kikori Village(Date: September 2, 2004)


58

References

(Collected data and information)


59

Collected Data and Information

Relating to Natural Gas Development and GTL Manufacturing Projects in Papua New Guinea

( From July to September, 2004) Rference No.

Title Status Date of Issue

Prepared/Issued/Published

by

Remarks (Prepared for,

etc.) 1.0 Oil and gas reserves and properties

1.1 1.2 1.3 An Overview of the

Petroleum Potential of Papua Mew Guinea and its Undeveloped Gas Resources – An Independent Review and Assessment

Gerard Manggal (Separately filed.)

1.4 Brief on Gas Reserves & Processing Potential in PNG

June 6, 2001

Spays International Ltd.

1.5 Moran 1X, 2X Moran 5, Gas Composition, etc.

June 14, 2001

Spays International Ltd., etc.

1.6 Proven Reserves at end 1992 – The Middle East holds over 65% of the World’s total proved reserves of oil

1992

1.7 1.8 1.9 1.10 Summary of PNG

Petroleum Reserves

1.11 Gas Analysis Calculation of OGIP for Stanley Well

2.0 Study reports & papers

2.1 Kopi 30,000 B/D Refinery Environmental Plan-Inception Report

Original May 27, 1994

LeProvost Dames & Moore, Perth, Australia

The PNG Refining Company Pty Ltd

2.2 Kutubu Petroleum Development Project - Environmental Plan

Original March 1, 1990

NSR Environmental Consultants Pty Ltd, Hawthon, Australia

Chevron Niugini Pty Ltd

2.3 Moran Field PNG – A Fair Market Value for the MRDC 20.5% in PDL5

Nov. 12, 2001

DAVID Heron Associates (DHA), Brisbane,

Mineral Resources Development Company


60

Rference No.



by


etc.) Australia (MRDC), PNG/

(Separately filed) 2.4 2.5 2.6 ROKSAVE Volume 1(1) -

Geology Department Trains Environmental Science Students in Mineral and Petroleum Resource Awareness

Oct., 1993

Newsletter of the Geology Department, University of Papua New Guinea

2.7 Motukea Island Oil Refinery, Papua New Guinea

Sept. 1993

PNG Oil Refinery Pty. Ltd.

2.8 PNG LNG and Gas Utilization Study Final Report

Floppy diskette

Feb. 20, 1998

Worley Limited，NSW, Australia

2.9 PNG LNG and Gas Utilization Study – LNG Supply/Demand Study

Floppy diskette

Feb. 5, 1998

Worley Limited, NSW, Australia

2.10 Tolukuma Gold Project, Dome Resources PNG Limited

2.11 Past Experience, Future Oil Price of Oil and PNG Oil Pricing Policy by F. K. Rickwood

Highland Pacific Group

2.12 Ramu Nickel Project – Feasibility Study

National Gas Corporation Limited （NGC）

2.13 Corporate Business Plan, 2003-2020

2003-2020

Quantum Resources International Port Moresby, PNG

National Gas Corporate Limited (Separately filed.)

2.14 2.15

3.0 Proposals, pamphlets and catalogues 3.1 3.2 3.3 Gas Commercialization:

Efforts to Secure PNG’s Economic Future

Floppy diskette

Paul Tiensten, Director Petroleum, Department of Petroleum and Energy

3.4 3.5 Ditto. Ditto. Ditto. Ditto. 3.6 3.7 Australasia Upstream Aug., Wood (Separately filed.)


61

Rference No.



by


etc.) Service, Papua New Guinea- Reference Section Update

2000 Mackenzie

3.8 3.9 3.10 Mining and Petroleum

Exploration in PNG – Problems and Solutions

Nov., 1993

PNG Chamber of Mines & Petroleum

3.11 Northern PNG, Integrated Methane Complex – Single Train 16,500 BPD GTL Plant: Footprint

ITL//Rentech Inc, Jakarta, Indonesia

3.12 Welcome to the PNG GAS Project Outline Presentation

1999

PNG Gas (Separately filed.)

3.13 Syntroleum – Howard Weil Energy Conference, New Orleans

April 1, 2003

Syntroleum GTL patent holder(Separately filed.)

3.14 Syntroleum – Monetizing Stranded Gas

Sytroleum GTL patent holder (Separately filed.)

4.0 Conferences and seminars

4.1 Conference Announcement - Eighth Papua New Guinea Mining & Petroleum Investment Conference in Sydney, December 6 – 7, 2004

Dec. 6 – 7, 2004

4.2 Text of Address by Secretary of the Department of Mining and Petroleum, AIC Conference on Mining and Petroleum, Port Moresby, November 17, 1993

Nov. 17, 1993

4.3 4.4 2nd Annual Conference,

PNG Mining & Petroleum, PNG Project Finance Revisited, Divisional Director of AIDC Ltd. November, 1993

Nov., 1993

4.5 2nd Annual AIC Conferences, Landowner Involvement, Resource Project,

Nov. 17, 1993


62

Rference No.



by


etc.) November 17, 1993 by Paul Enerau LLB

4.6 2nd Annual Conference, PNG Mining & Petroleum - Keynote Address by Prime Minister, November 17, 1993

Nov. 17, 1993

4.7 2nd Annual Conference Port Moresby, November 17-18 , 1993, PNG Mining and Petroleum Seminar by Garden Ridgeway, Australia

Nov. 17-18 , 1993

4.8 Conference – November 18, 1993, PNG Mining & Petroleum, Lihir Project Update

Nov. 18, 1993

4.9 4.10 AIC Conference, Port

Moresby, November 18, 1993 – Speech by Minister for Mining and Petroleum

Nov. 18, 1993

5.0 Memorandum of understanding (MOU)

5.1 5.2

6.0 Magazines 6.1 M&P, Mining and

Petroleum Investment, Papua New Guinea Profile

Original May, 1996

6.2 Paradise Original Vol. 4, 2004

Air Niugini

6.3 Prime Original May – July, 2004

Mills Media

6.4 PNG Resources Original 2004 6.5 PNG Resources Original 2003 6.6 PNG Resources Original 2001 6.7 PNG Resources Original April –

June, 1999

7.0 Laws, acts, rules and regulations

7.1 Independent Sate of Papua New Guinea, Oil and Gas Act 1998

1998 (Separately filed.)


63

Rference No.



by


etc.) 7.2 Certificate of

Incorporation – National Gas Corporation Limited

Jan. 14, 1999

7.3 Policy Handbook – Department Petroleum and Energy, Petroleum Division

April, 2003

7.4 Section 8 Policy 7.5 Independent State of

Papua New Guinea – Government Statement on Natural Gas Policy

Original Sept., 1995

7.6 Independent State of Papua New Guinea – Oil and Gas Act, No.49 of 1998

Original Feb. 5, 1999

7.7 Independent State of Papua New Guinea – Oil and Gas Act, No.10 of 2002

Original 2002

7.8 Current Status of Papua New Guinea Revenue Law relating to Liquefied Natural Gas Projects

Nov., 1993

Ernst & Young

7.9 Getting the Act together – The urgent need for PNG to establish an appropriate legislative and fiscal regime for gas

Fern Consultants Limited, Port Moresby

7.10 The International Price of Oil and PNG Oil Pricing Policy

7.11 Ministerial Statement on Natural Gas Development delivered to Parliament

Nov. 17, 1993

Ministry of Mining and Petroleum

7.12 Independent State of Papua New Guinea – Companies Act 1997

Floppy diskette

1997

7.13 Independent State of Papua New Guinea – Companies Regulation 1998

Floppy diskette

1998

7.14 Collection of Salary or Wages Tax Rates of Fortnight Salary or Wages Tax Reduction

Effective Jan. 1, 2004

Internal Revenue Mission, Taxation Office

7.15 Pamphlets of IPA (Investment Promotion Authority)

IPA (Investment Promotion Authority)


64

Rference No.



by


etc.)

8.0 Statistics 8.1 Annual Business

Census – 1998 1998 National

Statistical Office, Port Moresby

8.2 Demographic and Health Survey 1996 – National Report

Original 1996 National Statistical Office, Port Moresby

8.3 Papua New Guinea 2000 Census – Final Figure

Original 2000 National Statistical Office, Port Moresby

8.4 Economic Indicators Aug., 1998

National Statistical Office, Port Moresby

8.5 Export Index Dec., 1993


8.6 Data Sheet – Papua New Guinea 2000 Census Figures

2000 National Statistical Office, Port Moresby

8.7 National Income, Expenditure and Production, 1994-2002

1994-2002


8.8 Government Finance Statistics 1997 - 2002

1997 - 2002


8.9 International Trade Statistics, Export Statistics - 2002


8.10 International Trade Statistics, Imports - 2002


8.11 Abstract of Statistics Dec., 1998


8.12 Building Statistics Sept., 2000



65

Rference No.



by


etc.) 8.13 Consumer Price Index

2004 2004 National

Statistical Office, Port Moresby

8.14 Petroleum Exploration & Production Statistics

1986-2005

8.15 Annual Report on Petroleum Activity in Papua New Guinea

Dec., 2003

Department of Petroleum and Energy, Petroleum Division

8.16 8.17 8.18

9.0. Photographs 9.1 Papua New Guinea –

Port Moresby Original Reprint

ed in 1986

10.0 Maps and charts

10.1 10.2 10.3 10.4 Papua New Guinea,

Scale=1/2,600,000 Hema Maps,

Springwood, Australia

10.5 Papua New Guinea Topographic Survey, Port Moresby, Sheet 8379-III, Scale=1/50,000

Original

10.6 City Maps – Port Moresby, 2 sheets in total

Original

10.7 Papua New Guinea – General Reference Map, Scale=1/2,500,000

Original 2002 National Mapping Bureau, PNG

10.8 Joint Operation Graphic (Southern Highland, Gulf and Western Provinces), Scale=1/250,000, 7 sheets in total

Original Feb., 1981

Royal Australian Survey Corps.

10.9 Charts - Philippine Islands to Solomon Island, Scale= 1/5,000,000


Japan Coast Guard, Tokyo

10.10 Chart – Papua New Guinea South Coast, Scale = 1/300,000


Australian Hydrographic Service


66

Notes: Unless specified in the column of “Status”, all are hard copies.

パプア・ニューギニアにおける天然ガス開発及び

GTL等製造事業に関する予備調査

要約

パプア・ニューギニアにおける天然ガス開発及び GTL 等製造事業に関する予備調査（要約）平成 16 年 12 月

1

パプア・ニューギニアにおける天然ガス開発及び

GTL 等製造事業に関する予備調査（要約）

本予備調査は、パプア・ニューギニア独立国 (PNG)の油田、ガス田の開発状況、将

来現地側の事業主体となりうるパプア・ニューギニア国家ガス公社（National Gas Corporation Limited：NGC）などの石油開発関係者が抱いている意向、開発方針、開発計画等を調査し、将来、本邦企業（商社、石油精製会社、石油開発会社など）が本調査で提案する事業への参入を決定するに当たって実施しなければならない本格的なＦ/Ｓ調査に向けて必要となる資料、情報を事前に収集、整理することを主な目的とする。以下に、本調査の内容を要約する。 1. 調査の背景

① PNG 本島の西部の中央山岳地帯（平均標高 1,200ｍ）に位置する南部高原州(Southern Highlands Province)の州都メンディ(Mendi) 周辺では 1992年から原油の商業生産が行われている（Figure- 1a及び Figure-1bを参照）。また、1994 年には、同地域の Hides において可採埋蔵量約 6 Tcf（Trillion cubic feet）のガス田の存在が確認されている。同地域を中心とするパプア堆積盆地（Papuan Basin）全体では 14、15 Tcfの可採埋蔵量があると推定されている。

② ガス田の存在が確認された 1994年当初から、同地域で生産される天然ガスを、

3,000km 以上の長距離パイプラインでトーレス海峡を挟んで南に隣接する豪州クインースランド州の主要な需要家に直送する事業が計画されていた。しかし、同計画は、7,000億円以上の膨大な資金が必要とされ、かつ、豪州のガス需要変動の影響をもろに受けるほか、パプア・ニューギニアが受ける恩恵も少ないと判断されため、2004年 12月現在、凍結（塩漬け）されており、豪州へのガス直送計画については当分再検討は行われない状況となっている。

③ パプア堆積盆地から採取される天然ガスを北部の海岸（Vanimo又は Wewak）

或いは南部のパプア湾の海岸線（Kikori）付近までパイプラインで輸送し、LNG (Liquefied Natural Gas) 、LPG（Liquefied Petroleum Gas）、或いは GTL (Gas-to-Liquid)等に加工し、輸出する計画が PNG政府によって計画され、これらの計画に対して、現在、パプア・ニューギニア国家ガス公社の総裁は、ガス田開発の日本側のパートナーを求めてきている。

④ 近傍にマーケットがなく、また、長距離パイプラインによる輸送等が必要とな

る開発の難しいガス田は、「Stranded（取り残された）Gas」と言われ、この「Stranded Gas」の最新で、有効な開発手段の切り札の一つが天然ガスの「GTL化技術（Gas-to-Liquid：常温・常圧での天然ガス液体燃料化）」である（Figure-5bを参照）。GTL プラントは、現在、世界で 3ヶ所稼動しており、20 ヶ所で建設が計画されている。

⑤ 原油の高値が続き、GTLなどの新エネルギーも採算ベースに近づきつつある今

日、天然ガスを原料とする LNG、GTL、メタノール、DME(De-methyl Ester)


2

などの開発が現実性を帯びてきている。

2. 事業の意義と目的 ① 地球環境保全

天然ガスを GTL 化することにより、ほとんど NOx、SOxなどの大気汚染物質を含まない燃料を製造することが可能である。本事業は地球環境保全及び大気汚染防止に大いに貢献する事業である。

② PNG の外貨獲得と民生向上

GTL 原油として輸出することにより、外貨を獲得し、天然ガス、GTL 等を原料、エネルギーとした PNG の地場産業育成、電力などのインフラ整備を通じて PNGの民生の向上を図ることが可能となる。

③ 日本へのエネルギー安定供給

将来世界的に原油の需給が逼迫した場合に、エネルギー資源のほとんどを海外に依存するわが国は出来るだけエネルギー資源の多様化、生産地の地理的分散化を図る必要があるとするエネルギー安全保障政策に合致する。

④ 日本企業の参入

パイプライン、GTL プラント、FPSO（Floating, Production, Storage, and Offloading浮遊式海上生産・貯油・出荷システム）などの施設の建設には、膨大な資金が必要になり（GTL プラントの規模にもよるが、1,300～2,500 億円ぐらいになるものと予想される）、日本企業による資本参加、エンジニアリング、建設工事への参入、資機材、プラント輸出が期待できる。

3. 調査事項国家ガス公社等から天然ガスの埋蔵量、生産量等のデータを入手すると同時に、同

公社の意向、将来計画等をヒアリングし、プラントの建設予定地等を視察し、PNG にとっても日本にとっても相応しい天然ガス開発計画を策定する基礎資料収集と事業の概念設計を調査の目的とした。具体的な調査項目は以下の通りである。

（1）現地調査と情報収集

(a) ガス田データ（ガス井の数と位置、ガスの性状、埋蔵量、生産量等）の収集

(b) 坑井サイト、パイプライン・ルート、プラント・サイト、出荷バース等の予定地の踏査（地形図、海図等の収集）

(c) 現地の経済、社会インフラ等に関する情報収集

(d) 現地のステークホールダーに関する情報（規模、能力、人材、資本力等）


3

(2) ガス田の埋蔵量データの評価

(3) 天然ガス開発計画と有効利用計画（PNG と日本共に恩恵をもたらすプロジェクト）

(4) 建設コストの概算 (5) 世界及び日本のエネルギー動向調査など

4. プロジェクトの内容

4.1 基本計画（概念設計）

パプア堆積盆地（Papuan Basin）全体では 14～15 Tcfの可採埋蔵量があるとされ、

LNG、GTL を製造するには十分な埋蔵量があるものと判断する。これらの施設容量と

しては、Table-1に示した 4つの天然ガス生産量のケースを想定した。

Table-1 天然ガス生産量とパイプライン及び GTL製造プラントの施設容量

天然ガス生産量

コンデンセート(NGL)

GTL 原油

LNG

SPM + FPSO ケー

ス (MMscf/d) (bpd) (bpd) (MMt/y) (dwt)

1 1,200 40,000 120,000 8.00 260,000

2 900 (36”φ)

30,000 (12”φ)

90,000 6.00 200,000

3 600 (30”φ)

20,000 (10”φ)

60,000 4.00 140,000

4 300 (24”φ)

10,000 (8”φ)

30,000 2.00 80,000

注）MM: Million, NGL: Natural Gas Liquid, SPM: Single Point Mooring（一点係留システム）, FPSO: Floating Production, Storage and Offloading, scf: standard cubic feet, bpd (or b/d): barrel per day, dwt: dead weight ton

4.2 プラント及び施設への概略投資コスト（CAPEX）

PNG の天然ガスの埋蔵量、地理的条件、プロダクツの市場性などから、PNGにおい

て天然ガスから GTLを製造し、日本を初め、中国、韓国、台湾、フィリピン、ベトナ

ムなど東アジア、東南アジアに GTL原油として輸出することが市場の多様化を図る上

で最も望ましいと考える（Figure-6cを参照）。


4

本事業の施設への CAPEXは、技術的に最も可能性が高いと思われるTable-1に示し

たケース２におけるパイプライン、FPSO 等について、下表（Table-2）に示す。その

範囲は、1,200 Million US$（GTL日産 30,000バーレル）から 2,500 Million US$（GTL

日産 90,000バーレル）である。

Table-2 プラント及び施設への概略投資コスト（CAPEX）プラント及び施設能力/サイズ数量総額

US$ Million Dry gas transmission lines to FPSO

36 ”φ 330 km 453

Condensate transmission line to FPSO

12 ”φ 330 km 151

PLEM+ SPM 200,000 dwt 1 set 15 FPSO Hull（FPSO 船体） 200,000 dwt（中

古タンカー） 1 ship 50

GTL Plants 30,000 bpd 30,000 bpd 30,000 bpd

1 train 2 trains 3 trains

600 1,200 1,800

計 1,265/1,875/2,465

注）PLEM：Pipeline End Manifold

5．パイプライン、FPSO、GTL等に関する技術に関する日本企業の経験、実績日本は、パイプライン、FPSO の設計・製造・建設・据付については、世界のトップ

クラスの技術を有している。この次世代クリーンエネルギーとして期待されているGTL

技術については、日本でも石油公団が FT 合成油プラント、JFEグループが DME プラ

ントなどの実証試験により実用化の目処が立っており、すでに中国など海外からの引き

合いがある。また、日本の大手エンジニアリング会社もナイジェリアの GTL プラント

のエンジニアリング業務を受注するなど、GTLプラントに関するエンジニアリング能

力についても、日本は世界的な競争力を有していると言える。

6．結論と提言

GTL 原油は、硫黄分をほとんど含まず、パラフィン分に富み、芳香族分が少なく、

クリーンな燃料としての利用が期待されている。油田から採取された原油からできる石

油製品と同様に容易に取り扱うことが可能である。また、クリーン燃料としてのプレミ


5

アムが与えられ、高値で売ることができる。将来、原油の高値が続くようであれば、消

費地から遠い辺境の地で天然ガスの GTL化も採算が見込めるようになる。

従って、本予備調査結果を持って、日本企業（商社、石油開発会社、石油精製会社な

ど）の本事業への参加を促し、更に、本格 F/S調査の実施へ繋げ、将来本邦企業が資本

参加など事業への参入することを期待したい。

そのためには、速やかに、現地のステークホールダー（PNG 政府、公社、Exxon-Mobil

（米国）、Oil Search Limited (豪州)など）と協議し、資本、運転参加の可能性のある日

本企業と共に本格 F/S調査を実施する必要がある。

（以上）


6

添付図表

番号タイトル Figure-1a : Geographic Map - Overall Papua New Guinea (PNG) Figure-1b : Geographic Map – Bismark Sea- Wewak-Soutern Highlands-Kikori

Delta-Gulf of Papua Figure-5b : GTL Manufacturing Process (Typical) Figure-6c : Natural Gas Development and GTL Manufacturing Plan and Concept

(See Figure -1b.)

Figure-1a

Geographic Map – Overall Papua New

Guinea (PNG)

Port Moresby

Lae

Medung

Wewak

Kikori

Rabaul

Vanimo

Papuan Basin

F

igure-1b

Geo

grap

hical M

ap

– Bism

ark Sea – W

ewak – S

ou

thern

Hig

hlan

ds

– Kiko

ri Delta - G

ulf o

f Pap

ua

Kikori

Kopi

Hides

Moran

Kumul Oil Terminal

Gobe

Wewak

6°00’ 00” S

8°00’ 00” S

4°00’ 00” S

142°00’ 00” E 144°00’ 00” E

Mendi

Papuan Basin

Natural Gas CO2

Removal

Sulfur Removal

Synthetic Gas Production

Process (SR/ POX/

ATR)


Oxidants (O2(Air), H2O(Steam), CO2, etc.)

Distillation

Hydro- cracking

Synthetic Crude

Naphtha

Synthetic Gas(CO and H2）

H2

Gas Oil

Kerosene

H2

Figure-5b

GTL Manufacturing Process (Typical )

Fe, Co, Ru, etc.

(Domestic and overseas Oil Refineries)

Notes: 1) SR: Steam Reforming 2) POX: Partial Oxidation 3) ATR: Automatic Thermal Reforming

Ni

Wax, etc

（FPSO）

Kutubu Oil Field and

Central Production

Facilities (CPF)

Hides

Gas Field

SPM + FPSO (200,000 dwt Class)

36”φx 330 km - Dry Gas Transmission Line

12”φx 330km - NGL Transmission Line

Kumulu Oil Terminal +

SPM, Capacity:

60,000 to 150,000 dwt

20”φx 270 km Crude Oil

Export Line, Capacity:

200,000 b/d

Figure-6c Natural Gas Development and GTL

Manufacturing Plan and Concept (Draft)

P’nyang

GTL Plant of 30,000bpd

(Future)

(Future)

(Gulf of Papua)

(Province of Southern Highlands)

(Province of Gulf)

Pandora

Gas Field

Angnore Juha

Kutubu

（Legends & Notes）

： Dry Gas Line (Proposed)

: NGL Line (Proposed)

: Plants & Facilities (Existing)

: Main Gas Fields

Notes: 1) Natural gas will be dehydrated and separated into dry gas and condensate (NGL: Natural Gas Liquid) within fields.

2) Start of Kutubu crude oil production: 1992.

Gobe Oil Field

Moran Oil Field

This work was subsidized by the Japan Keirin Association through

its Promotion funds from KEIRIN RACE.

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