PNG Gas Finds Push LNG Plans

It is a little over 25 years since the Iagifu 2-X well drilled by Niugini Gulf Oil discovered Papua New Guinea’s first commercial oil field – the Kutubu field, which was put into production in 1992 by Chevron Niugini Pty Ltd. after they acquired the assets of Gulf Oil.

The field is located some 555 kilometers northwest of the nation’s capital of Port Moresby, on the southern edge of the Papuan Fold Belt in the remote Southern Highlands Province.

The discovery well was drilled on the Iagifu anticline, one of many large surface-defined structural features in the Papuan Fold Belt.

The Kutubu area is characterized by a series of southwest verging thrust folds, which create dramatic relief of over 1,000 meters between the valley floors and ridge crests. The surface geology is dominated by the Upper Oligocene to Late Miocene Darai Limestone, which is intensely weathered, forming a rugged karst terrain.

The entire area is covered in thick tropical rain forest, which makes access for exploration drilling incredibly difficult.

The main reservoir in the Kutubu field is the Early Cretaceous, Berriasian Toro Sandstone, thought to be a transgressive marginal marine and shoreface sand, which has excellent lateral continuity, splendid reservoir quality and is generally about 100 meters or more thick.
The main reservoir in the Kutubu field is the Early Cretaceous, Berriasian Toro Sandstone, thought to be a transgressive marginal marine and shoreface sand, which has excellent lateral continuity, splendid reservoir quality and is generally about 100 meters or more thick.

At the time of discovery, the field could only be reached by helicopter, but now an extension to the Highland Highway links the field to the coastal city of Lae – about 425 kilometers to the east of Kutubu as the crow flies, but a tortuous truck journey of more than 700 kilometers, as the highway snakes its way through high passes from valley to valley.

The weather was (and is) a major determinant for petroleum operations, when all the drilling supplies came to the drilling rigs by helicopter.

It was not uncommon to see a dozen helicopters circling around a drilling rig to drop off their supply loads in the late afternoon when the clouds had lifted off the rainforest canopy, after days of heavy and relentless rain.


The main reservoir in the Kutubu field is the Early Cretaceous, Berriasian Toro Sandstone, thought to be a transgressive marginal marine and shoreface sand, which has excellent lateral continuity, splendid reservoir quality and is generally about 100 meters or more thick.

After the Kutubu oil discovery, many international petroleum companies scrambled to drill more of these surface-defined anticlines, but only a few more (Gobe, Moran and South East Mananda) were found to contain any oil – and often only in separate fault compartments of these complex over-thrusted structures and with limited volumes. Many of the structures seemed to contain natural gas.

In 1987, British Petroleum discovered the large Hides gas field some 75 kilometers east of Kutubu. The Hides and adjacent Karius mountains form a pronounced pair of surface-defined anticlines 38 kilometers long by 8.5 kilometers wide, with a topographic relief of more than 1,500 meters above the adjacent Nogoli valley floor.

The Hides’ field gas is contained in the same Toro reservoir as at Kutubu, though delineation drilling has shown that the reservoir is likely to be considerably less faulted, based on communication between wells more than 12.5 kilometers apart.

The Hides gas field contains somewhere between 5.5 to 12.5 trillion standard cubic feet (TCF) of original-gas-in-place, with a most likely volume of 7.1 TCF.
The Hides gas field contains somewhere between 5.5 to 12.5 trillion standard cubic feet (TCF) of original-gas-in-place, with a most likely volume of 7.1 TCF.

Unfortunately, the Karius anticline does not involve the Toro reservoir in the hanging wall at depth, and though there may be a sub-thrust footwall Toro trap, it is well below the regional water level.

The Hides gas field contains somewhere between 5.5 to 12.5 trillion standard cubic feet (TCF) of original-gas-in-place, with a most likely volume of 7.1 TCF. It is the largest gas field discovered in Papua New Guinea to date.

Other structurally similar features that turned out to contain gas were the Juha, P’nyang and Angore fields – all located among the frontal features of the Papuan Fold Belt.


Faced with an abundance of gas discoveries in the late 1980s and early 1990s, the Petroleum Division of Papua New Guinea’s Department of Minerals and Energy (now the Department of Petroleum and Energy) commissioned a comprehensive study of its discovered petroleum reserves in 1992. The study concluded that if the gas from the fields could be aggregated there were adequate resources to underpin their development for supply to a coastally located LNG plant, from which LNG could then be exported to regional markets.

In 1995, after considerable consultation with the industry, the government devised a Natural Gas Policy, which set out revised fiscal and administrative plans for natural gas development.

These provisions were subsequently legislated and gave rise to the ability for companies to obtain petroleum retention licenses over discovered gas fields while they promoted and matured their plans for gas development and marketing, and a reduction in the petroleum taxation rate applicable to gas developments.

This stimulated development planning, and BP and Esso led a scheme to develop the Hides gas field for supply to a LNG plant at Madang on Papua New Guinea’s north coast, but the 1997 Asian financial crisis and consequent uncertainties about East Asian LNG import growth – and a terrible tsunami at Aitape to the west of Madang, highlighting the tremendous seismic risk of a north coast LNG plant location – put a temporary end to LNG plans.

For several years the gas field licensees, led by Chevron, examined the idea of developing the gas fields for supply to east coast Australian markets by an export pipeline, but that notion failed due to competition with Australian domestic gas supply, low gas prices and high infrastructure costs to build the gas export and delivery systems.

Meantime, the government continued to promote gas development by whatever means might be commercial. To support its plans, a seismic hazard study was commissioned by the Petroleum Division, which clearly showed that evacuation of the gas from the fields within the Papua New Guinea Highlands would best be done through the use of a southerly route down to the Gulf of Papua.

In August 2007, LNG development was again picked as the best method of monetizing the gas fields after the concept of transporting gas to Australia was abandoned. This time Esso Highlands Ltd. is leading a large consortium of gas field licenses and the state.

Plans are being turned into reality and construction is under way for a 6.9 million tons per annum LNG plant for the sale of LNG to Japan, China and Taiwan.


Hitherto these natural gas accumulations were distressed, but now they gave value.

Now that the government has been seen to negotiate and approve gas agreements and grant the various licenses for the field developments and pipeline and facility construction and operations, natural gas in Papua New Guinea has become a sought-after outcome from exploration drilling.

A small Canadian independent company, InterOil Inc., has in recent years discovered a large onshore Miocene reef in the eastern Papuan Fold and Thrust Belt. This is the Elk-Antelope gas field, which may have enough recoverable gas to support a separate LNG project.

In the Western Province, adjacent to the border with the Indonesian Province of West Papua, another consortium of licensees led by Talisman Energy of Canada are planning to aggregate gas from a series of small gas fields within the Papuan Foreland.

If these new plans mature, Papua New Guinea will have the capacity to establish 20 million tons per annum of LNG export by 2020, which would make it a significant regional LNG supplier – and enable it to strengthen its economy and pursue its many development needs.

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AAPG member Michael McWalter is a director of the Board of the Transparency International-Papua New Guinea, a director of the Circum-Pacific Council for Energy and Mineral Resources, and treasurer of AAPG’s Asia-Pacific Regional Council.

He first went to Papua New Guinea as British volunteer in 1976, working at a mission station in the Western Highlands Province.

After initial years working as a petroleum geologist throughout Asia and the Pacific, and working on many wells in PNG – including the Kutubu discovery well – he joined the Geological Survey of PNG in 1987 as senior petroleum geologist.

He was director of the Petroleum Division of the Department of Mining and Petroleum from 1990 until 1997, when he became adviser to the department under World Bank funding until 2006.

He currently is based in Port Moresby, Papua New Guinea, where he remains as a part-time adviser to the Department of Petroleum and Energy, engaged directly by the government.