Papua New Guinea seen as 'last frontier'

Papua New Guinea's sedimentary basins [49,519 bytes]

Papua New Guinea (PNG) is one of the final frontiers for oil and gas exploration and development in the Australasia region.

This is the view of Wood Mackenzie Consultants Ltd., Edinburgh, which said that, although large areas both onshore and offshore remain poorly explored, there is no doubt about the hydrocarbon potential of PNG.

"PNG's petroleum industry," said the analyst, "is finely balanced with respect to both producing assets and fields in the stages of final development. In addition, upside exists in the form of technical reserves mooted for development and also potential for continued exploration."

Licensing

Most of PNG is virgin territory, with the main area of focus being the Papuan basin, which has yielded significant oil and gas finds.

"PNG can be divided," said Wood Mackenzie, "into five major sedimentary basins: the Papuan basin, the North New Guinea basin, the New Ireland basin, the Bougainville basin, and the Cape Vogel basin."

Oil seeps were first reported in PNG in 1911, but the onshore territory was so difficult to work in-consisting mainly of jungle, swamp, or mountains-that it was not until the Arab oil embargo of 1973, coupled with availability of helicopters for field operations, that exploration began in earnest. Wood Mackenzie said that, until 1986, only about eight exploration licenses were typically in operation, but the Iagifu-2x discovery well drilled in 1986 raised interest in PNG.

"Consequently," said Wood Mac- kenzie, "a plethora of international oil and gas companies acquired a total of 28 new exploration permits over the period 1986-87.

"The majority of these permits reached the end of their first (6-year) term in 1992-93, but very few permits were subsequently extended to their second (5-year) term.

"Most of the blocks were relinquished due to a combination of prohibitive exploration costs and a lack of exploration successes, particularly in areas outside the main fold-belt region."

From a recent low of 18 exploration licenses active in 1994, 28 exploration licenses are now active. In 1997, the government awarded 10 new licenses, and eight were relinquished.

Drilling

Lack of onshore seismic, because of the country's difficult terrain, has caused much exploration to date to rely on surface geology.

"Drilling has, therefore, tended to be rather hit-and-miss," said Wood Mackenzie, "with very few valid tests being achieved with wildcat wells. For example, four wells were drilled on the Mananda anticline before Southeast Mananda-1x finally encountered a significant oil-bearing formation."

During 1987-90, wildcat drilling rose steadily to a peak of 13 wells in 1990.

Since 1993, said the analyst, drilling has switched mainly to appraisal, particularly of the Gobe and Moran finds.

The 250 million boe Iagifu-Hedinia discovery in 1986 and the later 50 million boe Agogo find were brought into production in 1992 as Kutubu field. Kutubu's initial production was 80,000 b/d, and peak output was 147,000 b/d in March 1993. However, said Wood Mackenzie, Kutubu is fairly mature and in decline.

Moran oil field was discovered in 1996 and has estimated oil and condensate reserves of 150 million bbl, while three reservoirs in Gobe field, discovered in 1991-94, have combined reserves of about 100 million bbl of oil and condensate. A gas find, Hides, has estimated condensate reserves of 110 million bbl.

Wood Mackenzie estimates initial liquids in place in PNG, including non-commercial finds, at 894 million bbl. Depletion of Kutubu field leaves remaining liquids reserves at 682 million bbl, of which 40% is condensate in gas fields, that are so far not lined up for development.

Developments

Moran field has not been confirmed for full development, but the field is on extended well test (EWT) through the Agogo production facility and Kutubu export pipeline.

Production under the EWT began Jan. 29 and involves two producers, although more may be added. An 11-km flow line to the Agogo unit has capacity of 60,000 b/d of oil.

The analyst said full development of Moran is dependent on results of the EWT and further appraisal drilling in the northwestern part of the field, but it noted that Moran Central could be fully on-stream by mid-2000.

A number of gas discoveries have also been made: Hides has estimated reserves of 5 tcf of gas; P'nyang, Juha, Kutubu, and Pandora A have combined estimated reserves of 1-2 tcf of gas; and a number of finds have reserves of less than 500 bcf of gas each.

A liquefied natural gas (LNG) export scheme had been proposed for exploitation of Hides gas field, based on a 3.5 million metric ton/year plant. Marketing studies were completed, as were preliminary negotiations with Asian gas buyers. "However," said Wood Mackenzie, "following the downturn of the Asian economies in late 1997 and the withdrawal of BP (Exploration Operating Co. Ltd.), the former project operator, in mid-1998, the prospects of commercializing PNG LNG have diminished."

Meanwhile, Chevron Corp. is leading a group considering development of a gas export pipeline from Kutubu, across the Torres Strait to Gladstone, Queensland.

The $1.3 billion proposed project also includes an offshore liquefied petroleum gas processing and storage facility in the Gulf of Papua.

Gas demand of 300 MMcfd is required for project feasibility, said Wood Mackenzie.

Project go-ahead, with first gas achievable in mid-2001 or early 2002, would depend on development of a proposed alumina refinery and electric power plant near Gladstone.