PETROLEUM SCENE HEATING IN FLEDGLING CRUDE EXPORTER PAPUA NEW GUINEA

Papua New Guinea's petroleum scene is heating again soon after it joined the world's ranks of crude oil exporters.

Operators, paced by a feisty independent based in Port Moresby, have drilled a string of discoveries near the infrastructure of the Kutubu development project that supports Papua New Guinea crude exports. All signs point to the increasing likelihood of good sized--maybe world class--oil discoveries that promise to sustain exploration and development interest beyond 2000.

It's a sizzling play that has seen a flurry of activity involving new licenses and changing interests in existing licenses as well as significant technological advances to cope with exploration in a daunting terrain.

Also in the offing are world class gas strikes that eventually could support a liquefied natural gas export project.

Meantime Kutubu development proceeds apace at center stage of the Papua New Guinea petroleum scene with a sharp boost in reserves extending the project's life.

And integration is the newest concept in Papua New Guinea petroleum. Efforts are under way to build the country's first refineries.

Most operators in Papua New Guinea believe they have merely, scratched the surface of the country's oil and gas potential. They agree there still will be frustrations and setbacks--political as well as technical--but the prevailing opinion is that these problems are no greater than they are in a number of other countries with similar exploration/development potential.

OIL SEARCH LTD.

Oil Search Ltd., the Australian exploration and production company based in Papua New Guinea, is fast becoming known as the latter country's oil company.

Although small compared with its southern highlands partners Chevron Corp., British Petroleum Co. plc, BHP Petroleum Pty. Ltd., Ampolex Ltd., and Japan's Merlin Petroleum NL and Marubeni Corp., Oil Search appears to be leading the way in Papua New Guinea's new exploration plays for 1994.

The company will be involved in 13 wells this year for an outlay of about $15 million to its own account. With onshore well costs running at about $7 million each, the overall program is likely to cost six or seven times that amount.

The program will consist of virtually continuous drilling throughout the year and suggests the potential still seen for petroleum discoveries in Papua New Guinea. That's especially true now that the groundbreaking Kutubu oil project has successfully completed its first 21 months of production (OGJ, June 29, 1992, p. 44).

Not surprisingly, the concentration of funds and effort that went into the Chevron Niugini Pty. Ltd. operated Kutubu development at the start of the decade curtailed the exploration effort in that period. But with the project now on stream there are two main incentives to resume exploration:

The first is to look for more reserves to replace those being depleted by Kutubu production.
The second is that with a production infrastructure and pipeline delivery system in place, the economics of future oil developments in the area are greatly enhanced.

AGGRESSIVE APPROACH

In the PDL 2 license area, which covers the Kutubu fields, there has been a resounding 54% success rate in exploratory drilling programs so far.

Oil Search says that anything close to that result in the current exploratory drilling program will ensure a continuation of strong oil and gas activity well into the next century.

The company decided to give its aggressive approach to Papua New Guinea exploration even more bite by issuing a series of sole risk notices to its joint venture partners near yearend 1993. The reasoning behind this move was that some of its partners have interests and priorities outside the country and do not have the same sense of urgency for new exploration programs in the region.

The onerous sole risk provisions in the joint venture agreement--which include immediate reimbursement of all exploration costs and payment of 1,000% of production revenue resulting from any development--have worked in Oil Search's favor, enabling the company to focus the joint venture's collective attention on exploration programs.

NEW TECHNOLOGY

Enthusiasm for exploration also is spurred by a new tool: strontium isotope dating.

The technique is particularly useful in the rugged highlands region, which is blanketed by the Darai limestone. Not only does the surface karst topography of this formation prevent access by seismic vehicles, but its porosity disperses the seismic energy so that the signal is lost.

The strontium isotope technique, however, involves simple collection techniques along traverse lines. Samples are then taken to a laboratory and analyzed to give a much clearer picture of the complex subsurface faulting in the highlands region than has been possible with surface mapping. The isotope work can differentiate variations in limestone age, which in turn can be used to determine upthrown and downthrown blocks in fault tines not discernible to the naked eye.

The isotope work has revolutionized mapping within the Kutubu production license area and the surrounding PPL 161 exploration license. Explorers can now see that most of the long, sinuous anticlines in the region are segmented all along their lengths. Many form several separate structures, and the overall pattern is a series of roughly parallel features running along the highland trend.

The plan, endorsed by all the Chevron group participants, is to begin close to the currently producing Iagifu, Hedinia, and Agogo fields of the Kutubu project and move gradually out to explore surrounding structures. The strategy makes economic sense because the existing infrastructure can be used to place any discoveries on stream more quickly and cheaply than starting in a virgin area.

The segmented nature of the structures suggests they are unlikely to be elephant scale discoveries, but the potential for accumulations holding 70-150 million bbl of oil is thought to be high.

The first Chevron group well for the year, 4X Gobe, was a successful test of the theory.

It was drilled about 18 km northwest of Southeast Gobe oil field, which is estimated to hold about 60 million bbl of proved and probable reserves, and about 10 km northwest of the 2X Gobe discovery.

The 4X Gobe flowed oil at rates of as much as 2,500 b/d through a I in. choke in January (OGJ, Jan. 17, p. 28)

When seen in plain view, the significance of the structural theory becomes apparent. Each of the three strikes is on a separate fault segment along the same elongated anticlinal trend (see map, p. 24). A fourth segment, designated Northwest Gobe, is still to be drilled.

GOBE APPRAISAL

Further drilling is planned on Southeast Gobe and 4X Gobe this year. The need to determine oil reserves with a reasonable accuracy has become more urgent with the new discoveries because it may have a bearing on the location of the production plant and design of a gathering system.

Present design plans center on the Southeast Gobe sector. Because the field crosses the permit boundary dividing PPL 161 operated by the Chevron group and PPL 56 operated by Mount Isa Mines unit Barracuda Pty. Ltd., negotiations continue on a unit operating agreement for development. Barracuda was appointed operator of the joint group Southeast Gobe project in September 1993.

The difficulty is that if substantial reserves are proved in 4X Gobe and perhaps the Northwest Gobe sectors, it could be more appropriate to locate the production system centrally in the 4X Gobe region. This area also has the advantages of being in a relatively cloud free valley--providing better access by air--and being closer to the existing Highland Highway road system.

In either case, Gobe development seems assured of a go ahead because of favorable economics owing to its proximity to the Kutubu export pipeline.

OTHER EXPLORATORY DRILLING

Oil Search's other exploratory wells include work on the Southeast Mananda structure northwest of Agogo field, where the most recent well was plugged this month. Southeast Mananda indicates an extension of the 1991 Agogo discovery.

There also is the 1X Moro, to be located on a feature overlooking the Kutubu project's main airstrip, and the 1X Northwest Iehi wildcat, to evaluate a structure south of the Gobe area. Farther to the northwest, the 1X Karius will appraise the gas reservoir in the BP/Esso/Oil Search group's Hides-Karius field.

Oil Search also will participate in two wells in the Gulf of Papua operated by Mobil Oil Corp., where Mobil has begun the country's first 3D seismic survey (OGJ, Jan. 17, Newsletter). One, on Portlock Reef, is slightly south of and on the same permit as Pandora gas field. The other is on the Pasca field permit to the north, again on a reef target apart from the Pasca discovery.

Oil Search also is in the last throes of a wide ranging study that has evaluated all the acreage in the Papuan basin outside its permits. Purpose of the survey, which Oil Search is conducting for a number of participants, is to provide a basis to rank all acreage and be in a position to know the value of any farmout or new permit opportunities as they arise.

The $1.2 million study is due for completion in June. It has looked at things such as oil source, maturation, and reservoir and tectonic influences and made comparisons with other areas, such as the geology of the Northwest Shelf region off Western Australia.

Recent exploration activity outside the groups in which Oil Search is involved has not been strong, but one program slated for this year in the highlands region about 15 km from the Ok Tedi copper mine is sure to be watched with interest. It involves evaluation of the huge Menge prospect on PPL 106 permit.

In January 1994 Australian explorers Santos Ltd. and Barracuda disclosed a $5.2 million farmout agreement under which Santos will earn 20% and Barracuda 35% in the permit by funding the 1 Menge wildcat. It is scheduled to spud before midyear. As now mapped, the Jurassic reservoir target has the potential to contain as much as 300 million bbl of oil or 540 bcf of gas.

Other interests in the program are held by First Australian Resources, Victoria Petroleum, and Sun Resources 15% each.

KUTUBU DEVELOPMENT

Despite renewed exploration activity, the Kutubu project still occupies center stage in Papua New Guinea oil operations.

The estimate of recoverable oil reserves has been upgraded recently from the original figure of 180 million bbl proved and probable. After 21 months of production, Kutubu reserves have been recalculated as 274 million bbl proved and probable--215 million bbl of that in the proved category.

The highest production rate achieved to date has been 149,000 b/d through the Kumul offshore terminal in the Gulf of Papua. The average flow during 1993 was about 135,000 b/d from 28 wells.

The Kutubu development, as originally conceived, has reached its plateau production level and is expected to show some decline this year. However, discoveries such as the Gobe fields, along with further development drilling in the current contributing Kutubu fields, may boost production levels again during 1995-96.

KUTUBU PROBLEMS

Two problems limited Kutubu flow in 1993. The first was weather downtime for tankers loading at Kumul terminal, which delayed production for 30 days in 1993. The other was the limit imposed by gas compression facilities in the field.

The Gulf of Papua is relatively shallow, and storms can quickly produce choppy seas that prevent offloading tankers from remaining at the loading buoy. The facilities were designed without storage at the offshore terminal end of the export pipeline and only 300,000 bbl of storage at the production center in the highlands.

This has proved to be inadequate to cope with more than 2-3 days of shipping downtime. However, construction of an extra 300,000 bbl of oil storage at the production center is to be complete this month. This will provide capacity for about 5 days of production, which experience indicates is the maximum length of weather downtime expected in the gulf.

Compression limitation is also being dealt with. A 25% increase in compression capacity is near completion at the field facilities.

The limitation stems from the Papua New Guinea government's stipulation of no gas flaring. Apart from using associated gas to fuel the Kutubu power plants, there is no alternative but to reinject the gas into the reservoirs.

Development work in Kutubu fields expected during 1994 includes the drilling of as many as seven wells--three of which will be horizontal wells in Agogo and Iagifu--to tap more reserves and provide added water injection capacity. There also is some consideration being given to introduction of a waterflood in the main Iagifu reservoir to supplement the natural water drive.

The other major new development at Kutubu is completion early this year of a $60 million road from Poroma near Mendi to Moro. This road, built as part of the Chevron group's commitments to the local communities, links the Kutubu project all the way to the coast at Lae via the Highlands Highway. No longer is the operation accessible only by air.

HIDES-KARIUS GAS FIELD

Perhaps even more intriguing than work at Kutubu is the highlands appraisal and potential development scheme under way in Hides-Karius gas field in PPL 138 permit northwest of the Kutubu operation.

The Hides gas project, which powers the Porgera gold mine, was Papua New Guinea's first commercial hydrocarbon development. It lies in production license PDL 1 in which BP has a 95% interest and Oil Search 5%.

The new scheme and an LNG development project have been legally separated from the Hides-Porgera arrangements and involve BP and Oil Search plus Esso, which is taking a farmout. Marubeni is negotiating to join the new group.

Potential for the LNG export scheme was boosted by results of 1993's 3 Hides appraisal well, which increased the indicated thickness of the gas column to a hefty 860 m. Even then, 3 Hides did not reach a gas/water contact, and the partners believe the gas column could be more than 1,000 m thick.

LNG PROSPECTS

Current proved, probable, and possible recoverable gas reserves at Hides are placed at 5-7 tcf. Even using a conservative figure, the 19 year contract to supply the Porgera mine with 150 bcf in that period will tap a mere 1% of the known gas reserves. That leaves a massive amount of gas for other uses, spawning the LNG project.

Hides will be probed further this year with the 1X Karius appraisal, which aims to evaluate the southwest flank of the field. Hides and Karius are part of what the joint venturers interpret as a double headed structure. If the new well confirms an unbroken reservoir across the two features, gas reserves will be sufficient to supply a 25 year LNG contract at about 4 million metric tons/year.

Development of Hides-Karius in this manner would have backup from the P'ynang and Juha/Baia gas/condensate discoveries in the Chevron group's nearby PPL 101 permit.

However, the difficulty with a Papua New Guinea LNG scheme is remoteness of the highlands and economics of shipping gas to market via an LNG plant on the coast. Pipelines are the answer, but the proposed route is a matter of debate.

Some favor a route south to the Gulf of Papua to a plant built perhaps on Yule Island about 100 km from Port Moresby. This would have the added virtue of allowing development of the untapped gas reserves, currently estimated at 2 tcf, in the offshore Pandora/Pasca fields operated by Mobil to give the overall LNG scheme a greater scale.

However, as seen with oil tanker movements in the gulf for the Kutubu project, water is shallow and seas treacherous. An alternative for the highlands project would be to send gas by pipeline to Papua New Guinea's northern coast across the Sepik region to Madang. This has two advantages over the southern route. Madang is a deepwater port and is much closer to prospective Asian markets.

Both schemes are very much in their infancy, but the major planners are treating them as serious possibilities for the future.

DOWNSTREAM PROSPECTS

The advent of Papua New Guinea as a crude oil exporter has raised the possibility of building a refinery in the country to supply domestic needs for gasoline, diesel fuel, kerosine, and fuel oil.

Any excess could be exported as product. At the moment, Papua New Guinea uses only about 8,500 b/d of oil, most of it diesel fuel.

Such a refinery also could obtain crude from other countries in the region to meet some of the country I s needs and allow more exports of the premium Kutubu crude.

The Kutubu project currently incorporates a small topping refinery in the highlands. It is capable of producing 100,000 l./day of diesel and aviation fuel. However, the market in the immediate highlands area has been limited, and the Chevron group operated the refinery only 50% of the time during 1993.

This may change with the opening of the Poroma-Moro road, allowing a wider market to be served, but it will always be a small operation.

TWO REFINERIES PLANNED

Plans for a complex refinery to be built in Papua New Guinea emerged during 1993, when two groups put forward proposals to the government. Both were told to proceed.

One scheme is backed by Galveston-Houston Co. of the U.S., which formed PNG Oil Refining Co. Pty. Ltd. (Pngorc) with plans to build a $75 million refinery at Kopi near Kikori on the Gulf of Papua coast at the end of the Kutubu oil pipeline.

The second proposal has been put forward by a group of CMPS&F, an Australian engineering and management group; PetroFac Inc., a U.S. refining design and construction company; Petimex an Australian company; and Curtain Bros. PNG, an Australian civil construction company. This group has formed PNG Refinery Pty. Ltd. (Pngor) to build a $160-190 million refinery on Motukea Island in Port Moresby Harbor.

Pngorc proposes to take 20,000 b/d from the Kutubu pipeline and produce kerosine, diesel, and jet fuel. Any reduced crude and surplus from the process would then be pumped back into the pipeline. However, this would require compensation to Kutubu partners because of the resulting reduction in quality of export crude.

Galveston-Houston proposes to take a 40% equity in its project and negotiate with Kikori landowners to take a 15% interest. Pngorc has asked the government for a 10 year tax holiday and relief from import duties for equipment needed for the project.

Pngor proposes to ship 30,000 b/d of Kutubu crude from the Kumul terminal and supplement this with crude feedstock from the Australian Northwest Shelf and Indonesia for a combined throughput of 40,000 b/d.

The group intends to place as much as 60% of shares in the Port Moresby refinery with private Papua New Guinea investors, as much as 20% with the refinery operator, and the balance with Papua New Guinea institutions and foreign investors.

Pngor is seeking a 5 year tax holiday from the government, as well as an exclusive right to the domestic petroleum market and a subsidy of 3/1.

The Port Moresby refinery would deliver product to existing storage in Port Moresby by pipeline and by coastal tanker to the country's other main coastal centers of Lae, Madang, and Rabaul. Surplus product would be exported.

The government has given the Port Moresby refinery proposal the go ahead to begin construction, which means the plant could go on stream as early as 1996.