Major finds triggering activity surge in US Gulf, Southeast Asia, West Africa; Western Europe, Mideast, Latin America seeing slight rise
Managing Editor - International
The offshore petroleum industry is on the brink of a high growth period worldwide that should last at least through 1997-98 and probably to 2002. The direct result of both the internationalization of the industry and the development and implementation of advanced technology, this growth in offshore oil production alone should exceed 3.5% this year, on top of 1994's 5.9%.
Last year's increases in oil production offshore were over five times that of the industry collectively, with the largest advances being made by Northwest Europe (19.5%). Gas production likewise was led by Northwest Europe (7.7%), the Far East (5.3%), and US Gulf of Mexico (2.4%). This year's figures are expected to be comparable.
Nineteen-ninety-four was essentially the year internationalization of the oil and gas industry began to produce results. Every major and almost all the large independents had, by this time, secured an international position for themselves and were getting about the business of acculturation and undertaking exploration, development, and production activities individually, in partnerships, and in consortia. Many of the larger national oil companies were venturing into foreign waters as well, and leading service and supply companies were right behind them, going where the business was.
As a consequence of the availability of concessions in most of the world's major venues, contracts proliferated, and with them, exploration and development activity around the globe.
Factors driving this international engine in 1994 and 1995 have been:
- Oil prices - As predicted last year, the 1994 price of oil rose from its record 1993 low of around US$14.00 a barrel to a painful but operable $16.50/bbl level. This price has, in turn, risen slowly during 1995 to a world average at the end of the first quarter of around $17.00 a barrel - a level that can be expected to continue to climb slowly, perhaps to a world average of about $18.20 by next year, due to growing global demand and the industry's inability to meet that demand.
World oil supply is growing at approximately half the rate of demand, which this year alone will increase by 1.2 million b/d, and next year by at least another 1.5 million b/d. And that supply is uncertain: North Sea and US Gulf oil is dwindling, Russian is torpid, and more than half the world's oil is now originating from politically unstable areas where war, civil violence, and political upheaval could disrupt its flow.
As a consequence, the price of oil is increasing, and, as it is, exploration and development around the world will be impacted, perhaps until 1998-2000. Structures that once looked uncommercial with oil at $16/bbl are being considered at least marginal and conceivably commercial now. Frontiers and more remote locations are looking more attractive, and previously shut-in wells may be reactivated.
This reversal of fortunes has its downside, however. With the potential for greater revenues, many countries may tighten their terms with demand for greater percentages of participation by their state or national oil companies, increased royalties, and addition of previously eliminated special petroleum taxes.
Furthermore, with prices by the end of this year perhaps at their highest in almost a decade, the industry will undoubtedly adjust to them by rethinking corporate planning, revising business to fit the new circumstances, loosening rigorous cost control and tight cash programs, and making new investments compatible with the higher price of oil.
- OPEC - OPEC members, like everyone else, ignored appeals for reduced output last year and pushed their production quotas to acceptable overages in a heated competition for maximum production levels. Likewise, as the previously mentioned figures demonstrate, non-OPEC oil producers such as Norway and the UK have also concentrated on reaching record production levels once more. OPEC, however, is now faced with Saudi Arabian leadership to freeze production at 24.5 million b/d in order to sustain and grow the price of oil even further. Most will likely go along with the restrictions, a half-million b/d of cheating, notwithstanding.
- Frontiers - With the price of oil inching upward, exploration and development is more inclined to move outward into some of the world's more interesting plays, out on the frontier of the industry in remote and difficult places where little search and discovery have taken place, into the deepwater provinces that look the most promising, and into select areas across the world where salt strata once obscured what lay beneath them. Particularly now, with very attractive terms in place, these frontiers are ripe for picking and can be expected to show considerable activity over the next six to 12 months or more, or until the higher price of oil pushes offering governments to alter their contracts once more in order to garner a greater share of the profits.
- Fast Track - With the 1993-94 movement to reduce costs wherever possible in the development and production process, the fast track approach to bringing a field onstream became a frequent method of choice, proved effective on both marginal and major fields, and has led to today's generally faster approach to each phase of the process.
As a result, to compress the development timetable, many operators have switched to one form or another of fast track development to help them maintain productivity and income flow. To that end, the formula frequently consists of letting out platform tenders shortly after a field's discovery, of having one project team rather than a sequence of teams, and of performing parallel work rather than sequential. It includes concurrent engineering, the building of equipment of the same basic design, and use of portable, reusable equipment. Components are ordinarily either comparable wellhead platforms - not normally staffed, if possible - or subsea equipment tied back to existing infrastructure, as well as floating production systems, topside process equipment, and production offloading systems.
Floating production systems, in particular, have been coming into their own recently. After first finding currency on deepwater sites, FPSs have proven themselves efficient at shallower depths. Today, they are almost essential to a fast track production program.
- 3D Seismic - With the exception of oil prices, perhaps no other factor has been more influential in the growth of production internationally than the great leap forward has occurred in seismic technology. Tremendous advances in acquisition, processing, modeling, and interpretation have changed the nature and greatly enhanced the value of seismic in exploration and development of hydrocarbons at every depth and within and below even the most difficult structures, including sheet salt.
As a direct consequence of the growth in computer technology, particularly parallel processing, whole new possibilities are available to the geophysicist that allow 3D seismic data to be acquired in a multitude of traditional and unique ways, including from one to four sources and up to 12 streamers in any number of survey patterns. Onboard processing is becoming more prevalent for both QC and delivery, and interpretation via very accurate 3D modeling is resulting in fewer wildcats being drilled, but more of them striking oil and gas.
The Auger platform.
US GULF OF MEXICO - There is a deceptive quality to the level of activity lingering in the Gulf of Mexico from last year. Although the industry experienced a surge in exploratory seismic and drilling in 1994, prompted by a brief peak in gas prices and new technologies - 3D, subsalt visualization, and directional drilling - the thrill is gone this year: gas prices have returned to their depressed level at about $1.40, and drilling is two-to-one development over exploration. In fact, the emphasis seems to be on getting the most from existing fields and leaving the risks of exploration for another day.
The gas market is expected to improve somewhat by year-end, as slowly increasing demand overtakes supply, but it probably won't be enough to attract absent operators back to the Gulf. Likewise, although oil prices are going to inch upward beyond the $18/bbl level, it isn't likely that there will be a huge surge in Gulf drilling; an increase, yes, but probably focused on further exploitation of existing fields, at roughly the same ratio as occurred last year with gas.
The problem is, the US Gulf of Mexico is a mature province where the best prospects available have been drained and there are no more easy finds. The best remaining reserves are in areas where exploration is prohibited for environmental reasons, or where the incentives for companies to explore and produce oil and gas in geologically difficult or deepwater prospects are absent. Unlike most other nations with oil and gas resources, the USA offers risk without a regime of fiscal inducements. Such incentives as a percentage depletion allowance, tax credits for production from difficult reservoirs, etc., helped build a healthy American petroleum industry, but are no longer in place.
Certainly, major oil companies continue to devote a small percentage of their exploration budgets to the Gulf, and some such as Shell are undertaking expensive deepwater programs, while others, such as Amoco and Phillips are exploring beneath the salt sill. But, for the most part, upstream investment is increasingly going to more attractive geologic and fiscal regimes elsewhere in the world.
ALASKAN WATERS - Elsewhere in North America (Mexico is covered below under Latin America), little of consequence is transpiring offshore. For a few months in 1994, it appeared Alaska was to enjoy a renewed surge of activity. Beaufort Sea developments gained some attention until their size and difficulty were appraised in the light of current oil prices. In the Cook Inlet, the hoopla that greeted the discovery of Atlantic Richfield's Sunfish Field diminished with the downsizing of the field several times, leaving the Inlet, and the state, at status quo.
There has been talk of perhaps easing the restrictions on drilling in the Arctic National Wildlife Refuge, now that the Republican Party dominates the US House of Representatives and Alaska's Senator Frank H. Murkowski is Chairman of the Senate Committee on Energy and Natural Resources. Chances are not good, however, unless oil prices double. In fact, Alaska's only offshore spur may be a recision of the prohibition of export directly from the state, now being considered in legislative committee.
CANADIAN NORTH ATLANTIC - Hibernia still plods along toward 1997. Its GBS was floated out of drydock last November to a deepwater site, where fabrication of walls and shafts will continue until mid-1996. Otherwise, the Grand Banks off Newfoundland have been quiet. No drilling is anticipated this year and, unless prices improve, maybe not next year. In the Nova Scotian fields, only Cohasset and Panuke are producing. Other fields await better days.
LATIN AMERICA - Latin America is almost entirely an onshore play. Major offshore activity, however, continues to characterize the most important exceptions: Mexico, Trinidad, Brazil, and Venezuela's Lake Maracaibo. Beyond these, exploration and development has been quite limited and promises to remain that way in the near future.
As elsewhere, there is a local desire to commercialize the energy sector in most Latin American countries, to expose that sector to market economics and place emphasis on efficient operations. To that end, one form or another of commercialization is being expressed in individual countries:
- Privatization - Argentina has lead the way by fully privatizing its energy sector, bringing in almost $10 billion in direct investment and debt relief and leading to an influx of new companies that have appreciably increased energy production.
- Restructuring - Mexico's Petroleos Mexicanos (PEMEX) underwent reorganization in 1992 and was restructured into four subsidiaries responsible for their own operations and profits. This, in turn, led to an increase in joint ventures with private companies and the letting of more turnkey contracts.
- Partnerships - Both Venezuela and Brazil have been moving in this direction. Venezuela has opened up to private domestic and foreign companies participating in exploration and production of marginal fields, and has formed a partnership with Exxon, Mitsubishi, and Shell to establish a major LNG export operation. And Brazil is trying to get around its constitutional prohibition of privatization by a program of "flexibilization" that will allow Petrobras to enter into partnerships on new investment projects.
Although Asia Pacific is the region most favored by international oil companies for exploration and production ventures this year, Latin America is second.
Risk levels have decreased somewhat over the past year, even though guerrilla groups continue to be active in several countries, and crime and labor unrest typify the dominant countries.
MEXICO- Last year's instability has devolved into this year's confusion and disorder. The government of Mexican President Ernesto Zedillo is in disarray, the economy is depressed and in deep trouble, and Mexican society is rent by a level of poverty and unrest that has resulted in open rebellion, protest, and further assassinations.
Political assassination, which began with last year's killing of PRI presidential candidate Luis Donaldo Colosio, has continued to the present. Ex-president Salinas's associates and his brother have been implicated in far-ranging graft and even some of the assassinations to such a degree that Salinas and others have left the country.
The Zapatista guerrillas in the oil-producing states of Chiapas and Tabasco continue to demand reform before they will cease hostilities, and the disgruntled Partido Democratico Revolucionario, demanding fair elections, continue to block PEMEX installations in Tabasco, despite government troop deployments, attacks, and arrests.
NAFTA has done little to lessen the disparity between Mexico's predominantly poor population and its small upper class, which led to these conditions in the country. Nor has NAFTA had a discernible effect on the deteriorating economy, which has eroded so badly US President Clinton has come to its rescue with billions of dollars loaned against petroleum profits.
PEMEX was given instructions to decentralize and earn more hard currency by improving its production via expansion of its areas of operation. It has been unable to relocate its exploration and production division to Villahermosa, Tabasco as planned, due to ongoing rebel activity, and despite several discoveries that could potentially expand the Campeche province, the depressed economy and devalued peso have seriously limited PEMEX's ability to invest in added production capability. In fact, in real terms, crude production has not increased significantly since 1991.
A few foreign-Mexican joint ventures continue to be active in Campeche Sound, but most are entirely Mexican. This, however, may change if PEMEX is able to venture into deeper waters. The risks, which have been almost nonexistent until now, will no doubt increase, but the potential of developing a wider offshore zone centered on the Campeche Reforma Trend will be worth the gamble.
TRINIDAD - 1994 witnessed considerable new exploratory activity in Trinidad and Tobago, with 11 exploratory wells. Oil production has been on the decline recently, but new discoveries off the eastern and southern coasts promise not only an excellent future as a gas producer, but the probability of self-sufficiency in crude oil until well into the next century. Amoco leads in development of both, with its Immortelle and Flamboyant Fields showing exceptional potential as they come into their full production. British Gas, another major developer of Trinidad's gas reserves, is developing the huge Dolphin Field, with its 2 tcf gas, as well as the DAB and DABO Fields. Five exploratory wells have already been spudded this year, with two to three more expected.
VENEZUELA - Across the Gulf of Paria, on its southern side, Venezuela's enormous Cristobal Colon gasfield complex lies awaiting development by the Sucre Gas consortium of Exxon, Mitsubishi, Shell, and PDVSA subsidiary Lagoven, mentioned above. The $5 billion plus project, still a controversy in Caracas, will eventually see the drilling of 55 wells from upwards of eight platforms, and the construction of a 50 km pipeline, an LNG plant and terminal. Originally intended to provide LNG to the US East Coast market, the project is now being aimed at meeting Western European needs initially, due to the expanded local US LNG program. Set to go onstream around 2000 with initial production of 2.3 million tons LNG a year, the project will, most likely, be delayed somewhat to allow prices to improve and to line up customers.
The marginal field program has had limited success, due to the lack of interest expressed in the fields offered for private investment, a few on- and offshore fields in the Falcon region of western Venezuela. This year, PDVSA plans to call for international tenders on new areas across the country, including the Gulf of Paria, east and west.
In its other major program, PDVSA continues this year with its Lake Maracaibo redevelopment program. The Lake's 11,000 active wells are being redeveloped through redrilling, reworking, and enhanced production such as cyclic steam injection. In addition, 3D seismic mapping of the entire Lake, which was completed last year, has led to several important new discoveries last year and this, including several giant light oil fields, as a result of a new, exhaustive exploration program is now underway in an effort to expand production from the current 1.4 million b/d to 5 million b/d of oil by the year 2000.
BRAZIL - Despite deepwater developments occurring more frequently now in several plays around the world, particularly the Gulf of Mexico's Shell Oil projects Auger, Mars, and Ram Powell, Brazil's state oil company, Petrobras, still leads the world in deepwater installations, completions, and production. Managerial and financial problems notwithstanding, the company has pressed on with its goal of producing oil from ultra deep Campos Basin prospects and has, in fact, broken the 1,000 meter depth with output from its world-record Marlim-4 well at 1,027 meters.
The company's unique deepwater research and development center, Cenpes, not only is proceeding with Procap 1000, aimed at production beyond the 1,000-meter depth, but is also pressing forward with Procap 2,000, aimed at developing the technological capability to produce oil from a water depth of 2,000 meters by the year 2000.
Petrobras has now installed the Petrobras XVIII, the world's largest FPS and its first semisubmersible built specifically for deepwater production only, at a water depth of 910 meters - deeper than any other production system in the world, whether floating, TLP, or otherwise. The new, $272 million semi services 16 wells at depths from 700-980 meters and has a capacity of 100,000 b/d oil. Pipelines, laid by the Stena Apache at a record depth of 886 meters, connect it to the Campos Basin network.
Recent discoveries of new fields as well as four giants in the Campos Basin, with more than a billion bbl in reserves, should augment Brazil's oil reserves by 10%. Production from these new fields, in the year 2000, could reach 1.5 million b/d, effectively achieving the long-time goal of national self-sufficiency. One of the fields, the Albacora Leste Field, at a water depth of 1,000 meters, alone holds 550 million bbl. All the while, the company's principal development projects continue apace, the 3 billion bbl Marlim Field wells as well as Albacora II, Enchova-West, Marlim I, Bijupera/Salema, and Carapeba III, and these, too, should push Petrobras's production level past national requirements before the year 2000.
ARGENTINA - Although the privatization program mentioned above has proven very successful for Argentina's petroleum sector, it has not made a measurable advancement in the offshore segment of the industry. Total's Hidra Field continues to be the only commercial offshore development so far, and Yacimientos Petroliferos Fiscales (YFP) and its successors have not ventured into Argentine waters other than via limited seismic acquisition and the offering and selling of licenses for a few nearshore blocks. (Samborombon Bay, off Mar del Plata and the Buenas Aires state, in the Gulf of San Matias, Gulf of San Jorge, and in Bahia Grande, Tierra del Fuego, and surrounding much of the Islas Malvinas [Falkland Islands].)
This year's election, which could bring opposition leader Fernando de La Rua to the presidency, could, however, see an amelioration of the privatization process, since it is very unpopular with the masses and many members of the Argentine oligarchy.
East of the Argentine Austral Basin is the Malvinas (Falklands) Basin, claimed by both Argentina and the United Kingdom. In 1994, extensive seismic surveying of the Islands' 200-mile exploratory zone revealed that the area has excellent oil potential, especially in the northern Falkland Platform and southern Falkland Chasm regions.
Licensing is expected to begin from the UK's local administration later this year, rejecting Argentine overtures for joint development. Drilling, if conflict doesn't interfere and oil prices cooperate, could begin in 1997, with first production in 2002-05.
The area could very well become the next decade's largest producing area. Data indicate that crude reserves in the South Atlantic surrounding the Falklands/Malvinas may exceed by more than 50% the reserves of the UK sector of the North Sea.
The decline continues. Despite record production, the maturity of the North Sea became manifest more than ever in 1994, as exploration activity dropped to its lowest level in decades - since 1968 in the Norway-Netherlands-Denmark sector, since 1981 in the UK sector. Overall oil output averaged 3.26 million b/d, achieving records in both North Sea divisions - 2.92 million b/d in Northwest Europe, 3.6 million b/d in UK waters. But drilling, both exploratory and appraisal, was severely down, due to upstream tax regimes, oil company uncertainties over licensing rules, and weak oil prices. Just 119 wells were drilled in the North Sea during the year as a consequence, 86 off the UK, 24 off Norway, six off the Netherlands, and three off Denmark and Ireland, representing an average decline of 38.5% for the region (12% UK, 8% Norway, and 57% Netherlands). Only nine new fields came onstream in 1994.
Norway's Ekofisk complex.
NORWAY - Perhaps the most significant event in 1994 in Norway was the nation's rejection of membership in the European Union, leaving the country in the company of inconsequential European states (Switzerland, Iceland, and Liechtenstein) in the European Free Trade Association and without a voice in energy policy development at a time when establishment of a European market regime for gas could drastically affect Norway's participation in that trade.
Norway is going the way of gas, just like the UK. In 1994, gas production was up 5% over 1993, averaging 2.91 bcf/d, and this despite the month-long maintenance shutdown of Ekofisk Field Center. New gas came from Elf's Lille Frigg Field and from Tordis, Sleipner East, Troll, and Ekofisk. Esso's Odin ceased production during the year.
Four new oil fields were brought on stream in Norwegian waters during 1994, Statoil's Gullfaks West and Statfjord East, Saga's Tordis, and Elf's Lille Frigg, contributing a total of 155,000 b/d of oil and gas liquids. Saga's Tordis was the most important of the group, since it was developed as a subsea satellite of the Gullfaks Field.
Total production reached 1.16 billion boe, a new record, which included 975 million bbl oil and gas liquids and 1.06 tcf gas, for an average of 3.18 million boe/d, up 11% over 1993.
The Norwegian Petroleum Directorate says that 1.318 billion tons of oil equivalent are held in the Norwegian sector of the North Sea still to be developed, and another 1.079 million tons of oil equivalent are said to be in discovery fields awaiting evaluation. Currently producing fields hold an estimated 2.0648 billion tons oil equivalent. Thus Norway has enough oil for the next 16 years, but it has enough gas for the next 111 years.
The country's showpiece, its huge, $4.79 billion Troll Field, one of the world's largest offshore gas fields, with recoverable reserves of 46 tcf gas and 400 million bbl of oil, is expected to go onstream next year with daily production of 2.3 bcf/d. A Statoil property, it is being operated in Stage 1 by Norske Shell.
In a continuing effort to expand its hydrocarbon play, exploration is being extended into the northern frontiers of the North Sea, outside Floro, and farther north still, into the Norwegian Sea's Voring and More Basins, where sea depth ranges between 800 and 1,200 meters. More than half the blocks receiving bids in the Norwegian 15th licensing round were in this mid-Norway region, where the Norwegian Petroleum Directorate estimates that up to 16 billion bbl oil equivalent remains to be discovered in mid-Norway.
The vast majority of North Sea deepwater drilling is taking place in these Norwegian waters, as Norway prepares for the future. Other fields, particularly in the central North Sea, continue to be drilled and brought into the development stage, while the numerous smaller fields, long discovered and awaiting development, will for the most part, still be left for future exploitation after the turn of the century.
NETHERLANDS - Continuing the trend in achieving record production levels, the Netherlands had a banner year in both gas and oil last year. Combined output reached an average of 453,000 boe/d up almost 36% over 1993. Gas production offshore was itself 30% over 1993, at 2.25 billion cf/d, propelled to this level by production from the five new fields that came onstream in 1993 and three fields that came onstream in 1994. The latter: Elf Petroland's K5A and K5D, first stages of the big K/4b-K/5a complex, Clyde's Q/8B Field, and Wintershall's L/8b Field.
There was also a significant increase in the production of oil and natural gas liquids off the Netherlands in 1994, up 89% over 1993 at 58,000 b/d, mostly from F3-FB, Horizon, and P15/P18 Fields, which completed their first year of production last year. Oil production from older fields, however, has continued to fall.
Exploratory and appraisal drilling dropped to less than half 1993's level at only six wells last year, five drilled by NAM and one by Elf Petroland. Although few, four are believed to have made discoveries, a remarkable success rate over 1993's dismal 23% successes.
DENMARK - Not to be outdone by other North Sea provinces, the Danish sector chalked up record production in both oil and gas in 1994. Oil production averaged 185,000 b/d, while gas reached a new level of 440 million cf/d. Exploration and appraisal drilling, however was almost non existent; just one appraisal well and no exploratory wells.
In an effort to renew interest in the Danish aquatory, the government announced a fourth licensing round that garnered 17 applicants. Awards have yet to be made public.
IRELAND - Nineteen-ninety-four could very well have been a turning point for the Irish offshore province. Before, it was barely noticed by most international players, but the new focus on the UK frontier west of the Shetland Islands, north of Ireland, and on the possible prospectivity of the Faeroes, farther west, has focused the spotlight on Ireland, particularly its own Atlantic frontier zones. To that end, two licensing rounds have brought considerable attention, especially from prior players Enterprise, Marathon, Mobil, and several consortia in the Slyne and Erris Troughs and the Porcupine Basin.
There was a slight increase in Irish gas production last year, up 2% to an average 262 million cf/d, most of which came from Marathon's Kinsale Head Field in St. George's Channel. The two exploratory wells drilled last year are believed to have been dry holes.
UNITED KINGDOM- Ambivalence characterized the UK sector of the North Sea last year. In keeping with the other sectors of the shelf, the UK enjoyed record production, with combined output of 3.6 million boe/d - 2.5 million b/d oil and 6.35 billion cf/d gas. But, also like the other sectors, the UK had one of its worst drilling and development years in more than a decade, with only 86 wells sunk and just nine new fields brought on stream, compared to 1993's 22 fields.
Discoveries were made, despite the few wells. Among the more significant discoveries, Marathon found the Dragon Field in St. George's Channel, Texaco discovered the Ptarmigan Field, Amerada Hess found its 21/16-2 and Dauntless Fields on the Central Graben's western edge and its Schiehallion Field in the West of Shetland play, while Clyde discovered 113/28-2 in the Irish Sea.
Gas accounts for more than 50% of the total reserves of the approximately 60 UK fields currently in development, or 14.3 tcf, with 2.3 billion bbl of oil. Estimates of reserves in the record 33 fields set for development indicate 5.8 tcf of gas and 902 million bbl of oil.
The cost of their development, which will require a capital expenditure of approximately ٣ billion, has been reduced appreciably by the impact of the CRINE initiative and attracted more interest in the UK shelf, not only for its major fields, but for frontier opportunities and prospective small fields.
Some analysts are now pronouncing the "West of Shetland" northwest Atlantic frontier zone the UK's next major oil province. Said to hold recoverable reserves of at least 5 billion bbl oil and a negligible amount of gas, the region has already seen at least five potentially commercial discoveries, with an additional nine more on the horizon.
Interest in the area is growing rapidly due to last year's tax reforms, thus the area's inclusion in the 16th round offering of concessions in the Faero-Shetland Islands region off northern Scotland has drawn considerable interest. Adding to the attraction of the area, have been several major discoveries that lead analysts to predict a major play with production, set to begin next year from BP's Foinaven Field at 60,000-100,000 b/d, reaching 500,000 b/d from at least seven fields by year 2005.
Russia & the Caspian
RUSSIA- In spite of the fact that the Russian aquatory contains an immense reservoir of oil and gas, and despite the fact that something of a democracy and a quasi-market economy appear to be holding sway in the erstwhile Soviet Union's principal state, Russia is an onshore province, and will remain that way until at least the second decade of the next century.
The lack of a cohesive bureaucratic structure with which to deal and a lack of infrastructure in which to work have made venturing into Russia's waters one of the world's riskiest enterprises and a formidable prospect before even considering the enormous difficulty presented by the arctic conditions that prevail over 95% of Russia's offshore petroleum provinces. International operators would like nothing more than to have a piece of the action in tapping these huge reserves, but, for the most part, the technology simply isn't yet available to tackle oil or gas production in permanently iced waters like those found in the Barents, Kara, Laptev, and East Siberian Seas. In the lower reaches of the Barents and in the Okhotsk Sea, though exceptionally difficult, it can be done. The cost, however, is far more than even the anticipated increase in oil prices permits and is, perhaps, more than those of the next century will permit as well. And this does not even consider the costs of arctic environmental protection.
As a consequence, international operators have slowed their previous rush to claim a share of Russia's approximately 550 billion bbl of estimated offshore oil and 250-300 trillion cu ft of natural gas. The risks at this time are overwhelming and precipitating a wait-and-see attitude even among the most adventurous.
Someday, Russia's Barents and Kara Sea provinces and its Okhotsk Sea province north of Japan will probably replace both the Gulf of Mexico and the North Sea as the world's big offshore petroleum plays for the first half of the 21st century. Currently, however, there are only two rigs working offshore in the Barents and Kara Seas and four in the Sea of Okhotsk.
Schtokmanovskoye, with estimated reserves of more than 141 tcf of natural gas, lies at approximately 1,000 ft water depth in occasionally iceberg-infested waters. Rosshelf's President Evgenii Velikhov has said that the field will be developed using three permanent, concrete gravity-base platforms linked to Murmansk via gas pipelines. First production, around 80 million cu meters a day, is predicted for 2001. Feasibility plans are being developed for Prirazlomnoye, an oil reservoir, to be developed concurrently.
Two other Barents Sea fields, Arkticheskaya and Dudlovskoya, are further from development but under study. Both also deepwater developments, Arkticheskaya will probably require 20-30 wells and an oil export line while Dudlovskoya, a gasfield, will be developed with five to ten wells with pipeline transport of gas and condensate.
Russia's other giant gasfield, Rusanovskaya, believed to hold gas reserves of 282 tcf, lies in only 50 meters water in the Kara Sea, but is accessable only two or three months a year without icebreakers. Russian and international geoexplorationists posit from Rusanovskaya and related structures that this region of the Kara Sea shelf may hold one of the world's most extensive concentrations of giant offshore gas fields. The Leningradskaya and Zapadno-Sharapovskaya Fields, just 30 and 80 miles south of Rusanovskaya, respectively, could both very well prove to be supergiant gas reservoirs, if current studies prove correct.
CASPIAN STATES- Undoubtedly the most exciting region of the former Soviet Union from an offshore petroleum industry standpoint, is the Caspian, where exploration, development, and production are ongoing, where international participation is acknowledged and desired, and where development should be relatively simple, compared to Russian waters. Of course, this area also has its problems, primarily the lack of an export route for hydrocarbons, somewhat arbitrary decision-making by heads of state and state oil enterprises, and, the various wars taking place between Azerbaijan and Armenia, Russia and Chechnya, and Turkey and the Kurds. For the most part, however, these situations have not affected the oil industry.
Considerable offshore development has occurred in the waters along the Aspheron Sill between Baku and Aladzha, Turkmenistan for more than a hundred years, but that development and the production from it has been very basic and is now generally inefficient or unproductive.
AZERBAIJAN- To rectify this situation, the Azeri government and its state oil company, Socar, were among the first of the CIS to seek international assistance in developing existing and new fields within their aquatory. Several relatively small contracts have been let for international development of individual fields, and one large, long-negotiated contract has finally been effectively completed for the 1.5 billion bbl Azeri-Chiraq Fields and a portion of the Guneshli Field. Socar, however, is still seeking to relinquish five to 10 percent of its share to another participant, perhaps Shell, now that Iran has been rejected by the other partners.
Guneshli Field needs extensive redevelopment to increase its production. The 1.5 billion bbl field is now producing some 120,000 b/d from nine platforms, but larger reserves are expected at a lower depth. The group that will handle the reworking of the field is composed of Ramco, Pennzoil, and Lukoil.
Ramco is also working on a redevelopment plan for Azerbaijan's oldest offshore field, the Neftianye Kamni, where production has dropped from 140,000 b/d in 1970 to just 16,000 b/d today.
KAZAKHSTAN - Across the Caspian from Azerbaijan and occupying most of the eastern shores is Kazakhstan, possessor of the giant onshore Tenghiz Field. It is one of the few former Soviet states that seem to have gotten its petroleum sector organized sufficiently well to attract major interest not only in its enormous onshore reserves, but in the prospect of what some say are equally giant oil fields beneath the shallow waters of the Kazakh sector of the Caspian. Tenghiz itself lies just onshore the huge expanse of the Caspian thought to harbor the major reserves.
A seismic study by Western Geophysical and DG Seis covering the entire 103,000 sq km of its northeastern Caspian Sea province is nearing the mid-point of a three-year program being conducted by state oil company Kazakhstancaspishelf and partners Agip, British Gas, British Petroleum/Statoil, Mobil, and Shell, all with equal shares. Following the study, E&P contracts are expected to be granted to the same companies.
TURKMENISTAN- In contrast, Turkmenistan desperately needs petroleum production but is having a hard time getting anyone's attention except for Iran's. It has put on several roadshows to attract interest in its aquatory, and is offering concessions to international operators in both joint venture contracts and production sharing arrangements. But few have taken the opportunity of getting involved in the Turkmen exploration and production program. Seven fields in various states of operability lie in its Blocks I and II. The other three blocks have seen little or no development.
Additionally, Turkmenistan is offering the remainder of its aquatory north of the Apsheron Sill. Seismic acquisition is preceding a bidding round, with bidders limited to participants in the seismic acquisition group. Due to the proximity of the Karaliogaz massif on the eastern shore, the area is considered highly prospective.
SAUDI ARABIA- Saudi Arabia has reached its goal of achieving a production capacity of 10 million b/d, but it has been difficult not only for the Kingdom but for the world market, having caused economic dislocation in the country and depressed oil prices in the world's markets.
As a part of its program to bring its production level to 10 million b/d, the Kingdom put renewed emphasis on its offshore fields in the Gulf, particularly those in the Safaniya area, including Marjan and Zuluf. The largest offshore oilfield in the world, Safaniya has multiple producing zones and currently has an output of approximately 1.5 million b/d. Saudi Aramco's upgrading program for the field has included 160 unmanned well platforms and five large six-well platforms. The company is continuing to expand its exploration and development efforts by using 3D seismic acquisition both to explore and delineate prospects.
The Saudi-Kuwaiti Neutral Zone lies at the northern end of the Gulf. Considerable development is occurring there, primarily of the Khafji and Hout Fields, which produce most of the Zone's 300,000 b/d
QATAR - Nothing significant has occurred in Qatar since last year. The primary thrust of activity is to further develop the enormous
North Field, the gas jewel of the Arabian/Persian Gulf that's almost as large as Qatar itself. Japan's electric utilities receive almost all the LNG it produces - more than 50,000 b/d natural gas liquids and 700 million cf/d of gas. With proven reserves of more than 150 tcf of gas, it is one of the world's largest known gasfields. Approximately 800 million cf/d are processed at the associated production and gas treatment plant.
The Emirate's other showplace is Elf Aquitaine's Alkhalij Field, about 100 km off the Qatari coast on Block 6. It is proving to be a major oil field in its own right, and is being developed with several delineation wells now being drilled.
UNITED ARAB EMIRATES - The Emirates are a disparate amalgam of dissimilar shaikhdoms with huge on and offshore petroleum reserves. Each oil-rich Emirate goes about its exploration and development without a care to what the other Emirates are doing, thus considerable duplication of effort occurs.
Abu Dhabi leads the fray with its competition with Kuwait for greater production levels (and OPEC quotas). Its intention is to jack up output by a million b/d by a frantic, widely expanded exploration and development program. On its Upper Zakum Field alone, it is undertaking a 100-well program, and at Das Island LNG complex, a US$1 billion expansion program is at full throttle with the intention of doubling production to 5 million tons a year.
Dubai is also in the midst of improving its production with its own expanded drilling program on the giant Fateh and SW Fateh Fields, which have been producing at a rate of 400,000 b/d. Some 24 wells were drilled there in 1994, and equal number are planned for this year. Sharjah, otherwise, is developing its giant Umm Al Aqiwain gas field and the Abu Musa oil and gas fields.
IRAN- Iran wants to participate in the exploration and development of both the oil and gas prospects in the Caspian and has offered to assist its neighbors via services and supply for the development of their fields and transit of Iranian territory as an export route for their hydrocarbons. Overtures have been made, as well, for participation in the consortia formed to develop Azerbaijan's giant Azeri-Chiraq structure and/or the huge Shakh Deniz structure south of it. The former has been ruled out, but the latter is being seriously considered. Several other small, initial projects have begun and agreements have been penned, but little work has begun.
Far more important at this time, is Iran's presence in the Arabian/Persian Gulf, where it has essentially completed rebuilding the majority of its oil and gas installations that were destroyed during the war with Iraq, and is extending its exploration and development to include virtually its entire Gulf province.
A major drilling program is underway that has attracted some foreign participation, namely Japex and Total. The intention is to build and maintain Iran's production capacity at 5 million b/d (from 3.5 million b/d). Unfortunately, the state's Islamic fundamentalism thwarts any real international involvement, since the specter of terrorism and violence is, rightly or wrongly, associated with the religious movement. Furthermore, many if not most of Iran's ruling mullahs continue to oppose any foreign equity participation in the country's natural resources and means of production.
Iran appears to be changing its attitude about Western participation in its petroleum sector, however. Recent contracts have been granted to European service and supply companies, to several operators, and even to a subsidiary of US-based Conoco. The latter was squelched by the Clinton Administration, but it indicates clearly that a new approach to the rest of the world is in the offing.
Most significant of Iran's Gulf activities is the extensive development of its South Pars Field, an extension of Qatar's gas supergiant North Field, which is being carried out by Saipem and the French company Technip. The development includes three appraisal wells, platforms, subsea pipelines, and a gas treatment plant at a cost of US$1 billion. Iran's share of the recoverable reserves are put at approximately 800 billion cu meters of gas. A joint development proposal has been made to Qatar which would include a pipeline, but nothing has been decided to date.
Elsewhere in the Irani aquatory, the giant Kharg Island offshore refinery, destroyed by Iraqi bombing, has been completely rebuilt by ETPM and is now producing at capacity - 170,000 b/d. It receives crude from most of the offshore wells on Fereidun, Esfandiar, and Cyrus Fields, and is currently being tied-in to others.
Iran has numerous other fields and redevelopment projects that are scheduling for work either by NIOC or contractors from both the Middle East and elsewhere. Accommodations appear to be just over the horizon.
North & West Africa
EGYPT - It appears Egypt is on its way to becoming a prime petroleum play, and nothing, including the disruptions and violence of the muslim fundamentalists in upper Egypt, will divert the country from that goal. The fundamentalists have had an unduly detrimental effect on tourism, but none on the activities of oil companies, their facilities or personnel.
Nineteen-ninety-four was another exceptional year for exploration and development in the country, particularly in Egypt's Gulf of Suez and Mediterranean shelf regions. New discoveries and increased production seem to be occurring daily. In fact, Egypt's oil production has been rising every year, and now is approaching a million bbl or 50 tons a year.
Several of last year's discoveries were significant, including Amoco's find just west of the massive Gulf of Suez October Field, which tested 5,500 b/d oil and 5.9 million cf/d gas, and Marathon's Ras El Ush-2, in the Gebel El Zeit sector of the southern Gulf of Suez, which tested 3,850 b/d oil. North of the Suez Canal's Mediterranean entrance, Agip discovered the Wakar-2 Field in its North Port Said concession, which averaged 26 million cf/d gas and 2,700 b/d condensate. And in the Egyptian section of the Red Sea, the BP/ONGC Videsh JV found several prospective structures that will follow BP's successful Zafarana Field development (20,000 b/d oil).
The Gulf of Suez is at the center of Egypt's oil industry and is the major activity area in the country, providing more than 80% of total production. Its fields yielded 40 million tons of crude oil last year, primarily from the Ashrafi and East Badr Fields, which have been put back into production after considerable workover.
Both 3D seismic and drilling (17 rigs) are occurring from Suez City to the Red Sea, with the highest concentration of activity in the Zaafarana (British Gas) and Abu Zeneima (IEOC) area. Further drilling and development is continuing at Abu Qur in the Zeit Bay and near both the October and North October Fields, in the area east of Abu Rhudeis and Budran Fields, and to the northeast of Belayim Field.
After establishing environmental restrictions for the southern sector of the Gulf, Exxon, Asmera Egypt (Gulf Canada), and Deminex have been carrying out exploratory drilling in the area.
Amoco is operating in the East Gharb region and General Petroleum is working the North Amr Field. Other activity areas include: North Darag, Ein Sokhna, East Sukheir, and el-Tur and Shadwan, on the Sinai side of the Gulf near the Ashrafi Islands.
Several major natural gas discoveries have been made on the Mediterranean shelf, including the most important Baltim concession off North Sinai held by Phillips. Discovery after discovery has been made there offshore the Nile Delta, a primarily gas-producing province. Agip/Elf, Amoco, Total, and Repsol have been the most active there. Abu Maadi Field continues, however, to lead the Delta area in production.
Shell Pecten also has found considerable gas reserves and deepwater oil off the Western Desert's Mediterranean coast, on Shakila and Marakia Fields near Alexandria, but any further activity there will depend on better oil prices.
LIBYA- Neighboring Libya has been very quiet offshore, concentrating essentially on further development of its massive Bouri Field, with its recoverable reserves of more than 670 million bbl of oil and 70 billion cubic meters of gas. Operated by Agip, which already has more than 50 wells completed, the field is now producing in excess of 100,000 b/d, but a number of new platforms are being readied with the intention of doubling the number of wells and perhaps the field's production as well.
TUNISIA- Considerable increases are anticipated this year as the giant, Gulf of Gabes ETAP (Entreprise Tunisienne d'Activites Petrolieres) British Gas Miskar Field, costing in the neighborhood of $630 million to develop, comes onstream this year with some 160 million cf/d gas from 12 platforms.
Other fields in the area showing considerable promise are BG's West Kerkennah and North Kerkennah Fields and the Salloum Field, Samedan's Gulf of Hammamet Cap Bon fields Isis (which begins production this year at 40,000 b/d oil), Tazerka, and Oudna Fields, Marathon's Ezzaouia and Zarat, as well as Elf's Ashtart Field.
West Africa's Gulf of Guinea, which attracted record numbers of major players in 1992-93, lost them in equally impressive numbers in 1994, but stands to regain most for a much better 1995. In fact, last year's record civil upheavals swamped almost the whole of West Africa. Only Nigeria's deepwater aquatory and the Cte d'Ivoire were truly out of harm's way, and Nigeria was essentially bankrupt and unable to meet its loan and joint venture obligations. Of the 18 countries lying along the West African littoral, civil wars raged in Sierra Leone, Liberia, Equatorial Guinea, and Angola, while violent labor strikes and opposition to the existing power structure ranged widely from Ghana, Benin, and Nigeria to Cameroon, Gabon, Congo, Zaire, and South Africa.
Most of the civil wars have played out and either dwindled to tentative states of peace or settled into fragile truces. As a consequence, the oil industry is returning in force, this year to drill at least 46 wells to explore and appraise what was left unexplored and unappraised last year. Although there were only 22 wells drilled in all West Africa in 1994, eight potentially commercial discoveries were made out of 17 wildcats, with estimated reserves of 310 million bbl oil. Another three stepout wells provided an additional 175 million bbl oil to the 700 million bbl of overall reserves.
West Africa's most active venues in 1994 and this year have been Angola, Nigeria, and Gabon, but last year, civil war and sabotage plagued Angola, corruption and empty coffers brought Nigeria to its knees, and labor riots and political violence plagued Gabon. This year promises to be different, however.
NIGERIA - The wholesale mismanagement of national funds, corruption, and theft by the former military regime left Nigeria effectively bankrupt, and the dictatorial regime refused to relinquish power to the duly elected government. National strikes attempted to right the situation, but were unable to hold out against the entrenched power structure and eventually gave in. Neither the necessities of life nor the financial commitments in international agreements, including joint ventures with foreign oil companies have been met. There has been an attempt to reshuffle the economy and a withdrawal from participation in numerous E&P contracts, however, to lessen some of the financial difficulty the country is now suffering.
The crisis-torn country has also been pushing production to garner as much revenue as possible, since it is heavily dependent on oil revenues to meet the needs of the nation and its disgruntled 90 million population. The goal is to up its quota to 2 million b/d, but it will be difficult to reach, even with governmental/NNPC creative accounting.
Considerable hope has been placed on development of Nigeria's deepwater province, where prospects are still to be determined. Extensive 3D seismic continues over extensive deepwater areas by all the leaseholders, and drilling is expected by several operators this year.
Probably two of the most devastating effects of cuts in NNPC/governmental participation in international development projects and the reduction of NNPC's interest in Nigeria's huge LNG export project from 60% to 49% or less, and the tacit withdrawal from the project to reduce wasteful gas flaring - now estimated at 2.5 bcf/d. With costs set now at US$4.5 billion, the LNG project is unlikely to come on stream until 1998 or later. And gas flaring will continue at least until 1996-97.
With the slowdown by the major oil companies who operate joint ventures with the NNPC due to the latter's failure to fulfill its $800 million JV obligations, other American and European companies are stepping in to JVs with local partners. Canada's Abacan has hit oil in OPL469, Consolidated Oil is now producing 3,000 b/d oil from Bela Field, Conoco E&P (ex-Dupont) has been drilling in OPL224, and Texaco has farmed-in with 30% interest into three Statoil/BP-held blocks ranging in depth from 200 to 1,000 meters, Blocks OPL213,217, and 218.
Finally, the prospect of forced privatization of majority interest in Nigeria's oil and gas industry, nevertheless, has a positive side. It is just possible that the entry of major operators as majority owners will bring with it a reduction in the mismanagement, corruption, and theft that has so characterized the industry for years. Currently NNPC has joint ventures with Shell, Mobil, Chevron, Agip, Elf, and Texaco.
ANGOLA- Last year, Angola was undoubtedly the most dangerous petroleum province in the world. This year, with the cease fire in the tragic civil war, a modicum of peace has returned and the country once more is one of the most promising West African plays, second only to Nigeria. At the height of last year's war, Texaco was forced to cease production of some 7,000 b/d, due to its facilities being within reach of the rebels, and operated from a barge out of range of rebel fire. Elf had to operate from Pointe Noire in the Congo, producing safely to FSOs offshore, after its base at Soyo was destroyed. Chevron pulled out its Cabinda Gulf non-essential employees when its operations at Malongo were attacked. And, Agip's personnel were fired upon, with several casualties. Altogether, at least 100,000 b/d of output were lost due to the civil war, of which 60,000 b/d was from offshore facilities. Production was therefore down approximately 120,000 b/d in 1994.
This year, hopefully, things will be different. Chevron and Elf, Angola's two major producers, have plans for more than $1.5 billion in expansions, and other Western companies are set to invest a further US$1 billion in new exploration. Chevron has a five-year 55-well offshore program for Cabinda areas B and C that gets underway this year. It is expected to increase company production by 500,000 b/d. Elf, on the other hand, will conduct exploration drilling over the next five years. Texaco is to spend $600 million over the next five years to boost the output of its Soyo concession in Block 2 from 60,000 b/d to 90,000 b/d oil. Texaco is operator and will contribute about $118 million of that amount, its partners will provide the rest - Braspetro 27.5%, Total 27.5%, and Sonangol 25%.
A few of the more significant discoveries in 1994 were Ranger's Block 4 exploratory well 4/23-1, which tested at 4,600 b/d, Elf's Block 3 north to south prospect with its Oombo 1 (4,770 b/d), Caama Centre 1, Caama Est 1 (4,400 b/d), and Quissama 2.
Perhaps most interesting of all is Chevron's Kokongo Field, which is Angola's first deepwater producer, located 40 miles offshore in Area B. Production this year is expected to reach 60,000 b/d oil, with ultimate production of around 390,000 b/d. When combined with several other Chevron fields in the area, total yield is expected to reach a million bbl or more. Altogether, nine new fields are due onstream this year.
Under Angola's new production sharing contract regime, concessions continue to be awarded. Block 15, a 4,500 sq km block has gone to Exxon's Esso Exploration. Esso signed with Sonangol for the new block which lies south of the Zaire/Cabinda zone and ranges in depth from 250 meters to well over a 1,000 meters. Esso will hold 40% interest. Partners are BP Exploration, Agip, and Statoil. Seismic is to start right away. Chevron has received Block 14, which also ranges into deep water. Two unspecified deepwater blocks are set to go to Royal Dutch/Shell and a Chevron-led group with Total and Agip. And negotiations are ongoing for several other offshore licenses, including deepwater Blocks 18 and 19, being sought by Amoco and Mobil, respectively. In the wings is extension of Chevron's Cabinda acreage into Areas B and C.
GABON - The political situation has stabilized somewhat in Gabon, but labor unrest continues and the economy remains dislocated. As a consequence, little activity occurred there last year, but this year, if the situation continues to improve, some 10 exploration and appraisal wells are expected to be drilled in 1995, and 16 in 1996, mostly by Elf Gabon and Occidental. The country's 36 offshore fields represent some 115,000 b/d oil production. Amoco and Phillips are believed to be negotiating for Blocks N93, O93, and R93.
COTE D'IVOIRE - Certainly one of the most promising turn of events in West Africa in 1994 was Cte d'Ivoire's considerable upturn in its hydrocarbon prospects. The country was already an offshore producer via its Belier Field, operated by Exxon-Shell, at 1,250 b/d oil production, and its 70 million cf/d gas producer Foxtrot, but these appear to only be the first of many potentially important fields in the Ivorian aquatory. Explorations on Block CI-11 have resulted in at least one major discovery by Global Natural Resources and United Maridian. Their directional well, Lion 1, tested 14,300 b/d from three zones. Union Meridian's first of four development wells, A-2, showed an additional 3,000 ft extension west of the discovery well, flowing in tests at 5,460 b/d oil and 4 MMcf/d gas. The discovery well tested 23,696 b/d oil and condensate and 65 MMcf/d gas. Nearby Panthere Field's discovery tested 732 b/d condensate and 30 MMcf/d gas. Production is set to begin in October.
Block CI27, which contains Cte d'Ivoire's major gas producing field, Foxtrot, has been awarded to Apache and its partners. Some 500 km of seismic is to be acquired, and at least one well will be drilled this year to test Foxtrot for oil.
In addition, state oil company PETROCI is offering several new concessions, including Belier-Outpost and North Espoir Fields, for joint venture. Both are past producers with proven reserves - Belier with about 10 million bbl and Espoir with about 65 million bbl.
Infrastructure for Belier is in place and in good condition, having been under Exxon operation. The Espoir Field was produced through an FSO. Blocks on offer include Blocks 93CI-01 and -02, with water depths ranging from shore to 2,000 meters. Block 02 contains the Belier Field.
OTHERS - Activity is up in 1995 in the other West African nations' aquatories, as well. Awards have been granted by Cameroon to Fina and Phillips for the Doula Basin, and another licensing is expected later this year. Five wells are foreseen in the country before year-end, two exploratory by Phillips and three appraisal wells by Shell Pecten, Elf, and Kelt.
In Equatorial Guinea, Arco was granted Blocks ML2 and 3 last year, and further licensing is expected this year. Mobil made a significant discovery in March of this year, but didn't disclose details. Walter Oil & Gas is expected to drill an exploratory well next year.
Exploration is up in Congo waters. Elf is negotiating for Marine Block X, and Occidental for XI and XII. Altogether, six wells are predicted for 1995, three exploratory and three appraisal, with as many as eight next year. Elf Congo is to drill a deepwater well this year on its Haute Mer block, a wildcat on its Marine III, and two appraisal wells on II.
Due to the political situation in Zaire, no activity is expected this year, although Chevron has a wildcat planned.
In Namibia, at least five wells can be expected as license holders meet their obligations. Sasol has one scheduled for this summer, while Chevron has one on the board for this year and one for next year. Norsk Hydro, as well, is planning two wells by the second quarter of 1996. Shell Namibia isn't planning any wells this year, but two next year to appraise its Kudu Field.
China & Southeast Asia
The world's most rapidly industrializing region, the region with the fastest growing population, the fastest growing economy, the fastest developing market, and soon to be the world's greatest energy consumer, is also the one of the prime destinations for the international oil and gas operators with an eye to the future. That region is China and Southeast Asia, where a whirlwind of offshore exploration, development, and production activity is centered on the South China Sea and its many gulfs and bays.
CHINA- The door is wide open to China these days. The "Middle Kingdom" is making enormous advances in conversion of itself into a major world economic and political power, including gradual democratic institutions and a somewhat Western-style market economy - which is the world's fastest growing for a major country, at 8-10% annually. To those ends, it is industrializing rapidly, and integral to that process is the development of a dynamic petroleum industry, because the country has become an oil importer, and it's not pleased about it.
With an aim of regaining self-sufficiency, the government is going after foreign oil companies, their finances and technology, like never before. It is now armed with a more liberalized tax regime and terms of participation international companies can live with, the offer of truly promising petroleum prospects, and a constantly improving economic and infrastructural base. And the world's majors are taking the invitation.
China's offshore is small but developing swiftly. The country's currently estimated offshore reserves of 6.2 billion bbl oil and 4.9 tcf gas provide a tremendous attraction for that development, and the political stability and legal framework provide a near risk-free environment for it. Twelve major fields are now in production, and several large fields and perhaps one giant are due onstream in the next few years - four this year.
Offshore oil production was 33.81 million bbl in 1993, up 19.6% over 1992 and was 41.89 million bbl (estimate) in 1994. This year, the figure is expected to reach 50 million bbl, next year, 61 million bbl - a whopping increase of 80%. Gas production has so far been negligible, however, and is not expected to reach a billion cubic meters until 1996-97 at the earliest.
Five fields are in production at this time in the South China Sea, Lufeng and Lufeng 13, Weizhou, Xijiang 24, and Hiuzhou, but three long-awaited fields are nearing readiness and should be coming onstream at the end of this year, beginning of 1996: in the Pearl River Mouth Basin, Phillips/Pecten's Xijiang 30 and Amoco's giant Liuhua 11 oil fields; and south of Hainan Island, Arco's giant Yacheng 13 gasfield.
These two giants are what China has been waiting for to really kick off its offshore province. Liuhua 11 is the largest oilfield in Southeast Asian waters, at more than 1.5 billion bbl oil equivalent, and Yacheng 13 is one of the largest gasfields, with 3.5 tcf gas. Together they are requiring almost $2 billion to develop - Liuhua with 20 horizontal wells being drilled between last year and 1997, a semisubmersible FPS and FPSO; Yacheng with a three-platform complex and 775-km, 28-inch pipeline to Hong Kong - due onstream this year.
Other South China Sea fields in development are Esso's Wenchang Field in Block 40/01 of the Hainan Straits between Hainan Island and the Luichow peninsula, BHP's Block 03/36 in the Pearl River Mouth Basin, Kerr-McGee's Block 04/06, and Arco's Blocks 52/12 and 63/28 in the Qiong Dong Nan area.
China National Offshore Oil Corporation (CNOOC) has signed approximately 100 contracts with foreign oil firms for exploration and development in its three major provinces, the South China Sea (Nanhai), East China Sea (Donghai), and Bohai Gulf. Another round is expected this year. China has had considerable success with its Bohai Bay province, where Texaco and BHP lead exploration. In the East China Sea, all the blocks offered have been licensed for exploration and development but two. Texaco, Chevron, Exxon, Shell, Japex, Agip, Maersk, Cluff, and Maxus have acquired the blocks.
PHILIPPINES- Sharing the South China Sea with China, the Philippines has been enjoying tremendous success with its Palawan Island prospect, where Alcorn, Shell, Occidental, and Philodrill have each had discoveries over the last year and a half. The West Linapacan Field, operated by Alcorn International, a Philippine-US consortium, looks to be a major field, with recoverable reserves of 109 million bbl. Production is growing from its initial 20,000 b/d to 50,000 b/d when fully operational.
Northwest of Palawan, the Oxy-Shell Malampaya Field, with reserves of more than 300 million bbl, along with Camago and Calao Fields are looking as though they, too, may be major fields in their own right. Because of them, Oxy has taken nearby deepwater block GSEC65, with its 1000 meter depth, considered to have enormous potential.
A number of additional wells will be drilled this year by Alcorn (SC14C), Ampolex (GSEC61), Kirkland Resources (GSEC60 and GSEC57), Occidental (GSEC65), and Philodrill (SC6A). Some of them were scheduled to have been drilled in 1994, but rigs were not available. In addition, a US$48 million exploration project is currently underway to ascertain other plays within the area. Eight other blocks off Palawan and in the Sulu Sea are currently being explored.
In November, a 12,000 sq km offshore tract, SPR94, is to be offered for exploration and development by the Philippine Department of Energy between the prospective northwest Palawan and Sabah basins.
MALAYSIA- With more favorable terms in place since mid-1994, Malaysia is once again attracting international operators to its venue, particularly to its deepwater provinces, where terms are best. As a result, a number of new prospects have been discovered using 3D seismic and expanded field exploration by major players, including Occidental, Esso, and Shell, which have each had outstanding successes and expect their extensive investment in offshore Malaysian E&P to produce even more.
Oxy holds about 5tcf in reserves in Block SK8 off Sarawak, and its latest wildcat, Cili Radi-1, tested at least 1 tcf gas. Other sizable Oxy discoveries in the block have been at Jintan, Seria, Selasih, and Saderi. Esso plans $3.1 billion in additional investments, most likely at its Jerneh Field off Terengganu, and Abu Field in Block PM8.
Shell's most recent discovery was the Kebabangan Field, with 1.5 Tcf gas, in Block SB-1. This in addition to its Kinabalu Field, one of Malaysia's largest oil and gas discoveries, will position Sabah as a contender with Sarawak for gas production.
Off Sarawak, Shell has an $8 billion project to develop some 11 gasfields and connect them to its MLNG II complex as a supplier to the Malay LNG Dua facilities in central Luconia. A network of linked platforms is being constructed from which both processing and drilling will be done. Collective reserves are set at 8.6 tcf gas. It is expected to be fully onstream by 2000.
Mobil was the first operator to sign a PSC with Petronas under the new liberal deepwater incentives. The company first received SK-A and SK-B off Sarawak, and last year was awarded SK-C and SK-D in the same area. Mobil is scheduled to drill this year.
The first deepwater block off Sabah has gone to Shell in a PSC with Petronas. Block G has water depths ranging from 1,000 to 1,800 meters. Shell already holds Block SB-1, south of Block G.
VIETNAM- The wunderkind of Asia, Vietnam is destined to become a major economic force in the region as it rapidly develops a diversified economic base and the highly sought oil and gas fields off Vung Tau in the Con Son Basin. These fields are said to contain more than a billion bbl oil and 5 trillion cf gas.
Nineteen-ninety-four was a particularly eventful year for Vietnam's petroleum sector. The downgrading of Dai Hung Field to 100 million bbl notwithstanding, wildcats abounded, and several important discoveries were made: BP's West and Red Orchid Fields in Block 06, Mobil's Blue Dragon in Block 05-1 (East), PEDCO's 11-2-RB-1X in Block 11.2, Petronas Carigali's Blocks 01-02 find, and Mitsubishi JVP's major discovery in Block 15-2, the Aurora Field, on the same horizon as nearby Bach Ho (White Tiger), with its 130,000 b/d production. The newly found field had one of SE Asia's highest test flow rates at 10,346 b/d oil.
In fact, Vietnam appears to have everything going in its favor, with enormous international interest in its petroleum provinces, numerous near-virginal areas available for exploration, reasonable and predictable terms for foreign participation, and a dynamic economy expanding rapidly to provide a national market for its petroleum production. Prospects even appear likely that pipelines will be built soon to provide added export to energy-hungry Thailand.
Unocal's Erawan Field, Gulf of Thailand.
THAILAND - Thailand is about to become an industrialized nation. Its economy is among the fastest growing in the world, its economic diversification is wide and far-reaching, its infrastructure excellent. And this is due, in no small part, to the presence of vast petroleum reserves within its Gulf of Thailand aquatory. Now into its 14th licensing round, the country has been a major player on the Southeast Asian petroleum stage for many years, and as each year goes by, it appears to progress both in its development of the reserves in its section of the Gulf of Thailand and in its terms of cooperation with international oil companies. As a consequence, Thai production has risen almost yearly. During 1994, for example, gas production was up 6% over 1993 at 9 billion cubic meters a year, oil up 5% over 1993 at 8.82 million bbl a year, with a total current oil equivalent output of 555.6 million bbl a year.
Most of that production has come from the enormous Bongkot, Erawan, and Funan gasfields and Shell's Sirkit oil field. Total's Bongkot itself accounts for a sizable percentage of output, producing more than 12.6 billion cu ft gas and 1.47 million bbl of condensate a year. But these are only the largest of a full range of fields currently producing in the Gulf of Thailand.
Among the most exciting newcomers are the Pogo/Maersk Tantawan Field in Block B8/32, which is becoming a major gas producer; Unocal's Pailin Field in Block B12/27, which holds at least 2 tcf gas itself; Ampolex's Kakrawake-1 in Block B10/32, with excellent showings, and Total's latest findings in the Bongkot Block, Nok Yoong-1 and Ton Sak-1, both indicating sizable reserves.
And even larger reserves are said to be sandwiched between Bongkot and Esso's 20 tcf brace of fields to the south in the Thai-Malay joint development area. This year, it was divided into three blocks for award to 50/50 joint ventures between the Petroleum Authority of Thailand Exploration & Production (PTTEP) and Petronas Carigali (two blocks), and Petronas Carigali and Triton Thailand (Block A18). PTTEP/Petronas will drill at least one well; Petronas/Triton will probably drill four. Furthermore, the as-yet-
unsettled Cambodian-Thai overlap zone is believed to harbor equally interesting formations on its extension of the Khmer Trough that will attract development into that sector of the Gulf once an agreement is reached.
Indonesia's Belida Field platform at loadout.
INDONESIA - Asia's OPEC member and a crude oil exporter, Indonesia's slowly dwindling production at 1.5 million b/d last year, is simply is not keeping up with the growth of its internal demand. Thus, it is expected to export only 500,000 b/d this year, less in the next five years until, by just after the year 2000, it becomes a net importer.
This is not to say the country doesn't have the reserves. It does. It is simply that international operators find more receptive venues elsewhere. Jakarta has, however, presented four incentive programs to attract outside E&P investment, but it still has a way to go before its excessive taxes and regulations are in line with the rest of Asia.
Gas is where Indonesia's future probably lies, and it is focusing considerable attention to conversion of its domestic energy base to gas while maintaining maximum revenue-producing export of LNG to its principal customers, Japan, South Korea, and Taiwan. Current gas production is approximately 70 billion cubic meters a year, of which 60% is exported, but programs are in place to boost production to 125 bcm/yr by the end of the decade. This despite the diminishing production at its Arun Field and LNG complex (now producing 12.3 million tons annually via six trains, but expected to expire by 2014.)
More than half of Indonesia's present export of LNG comes from the world's largest LNG plant at Pertamina's Bontang Field complex, with its six trains producing 15.4 million tons of LNG a year. Two additional trains are set to up capacity to 20.6 million tons.
If all goes as scheduled, Indonesia will both meet its internal demand and its total LNG export will stand at 28 million tons by the end of the decade. But this will require another giant field's input, and at this date, that can only be the huge, now Natuna Field with its 1.3 tcm gas - roughly half Indonesia's known reserves - held by Exxon and claimed by Vietnam and China.
Also in the Natuna Sea, Conoco is developing Stage II of its Belida Field, where 94,000 b/d oil will be produced, and Esso's $16-19 billion East Natuna Sea LNG project is centered on Esso's giant L Field, where reserves are estimated to be over 240 tcf. Conoco is working its three discoveries in Block B, and Marathon its Block Kakap. Chevron/Texaco are working off Nias in North Sumatran waters. And BP has invested $115.9 million on Lombok, West Lombok, South Sulawesi, and in the Moluccas, as well as on a venture in deepwater off East Timor.
Arco and partner Maxus Energy have discovered a new field off Java. The LES-1 well, tested 62 MMcf/d gas and 1,219 b/d condensate. The Northwest Java concession, on which the well was drilled, currently produces more than 200 million cf/d gas, 110,000 b/d oil, and about 10,000 b/d natural gas liquids.
Indonesian Celebes Sea tracts are to be offered by Pertamina, which will retain 85% of oil and 70% of gas production, with the balance left for production-sharing contractors. Lying off East Kalimantan, the almost 5,000 sq km blocks Sebawang I and II are to be awarded in at year-end. Unocal's Santan Field, also off East Kalimantan, will begin production in 1997 following installation of a 20-slot platform. This after delineation wells 8 and 9 Santan discovered fault blocks to back up the 1West Santan wildcat discovery well. Production is expected to reach 6,000 b/d oil/condensate and 50 MMcf/d gas.
Bass Strait oil platform.
AUSTRALIA - Once more, Australia has not had a particularly good year. There were a few hopeful finds in 1994 off the Norhwest coast, but far more dry holes than usual.
One important discovery, Chrysaor-1, a major gasfield, was made earlier this year by Wapet, the Western Australian Petroleum consortium of Texaco, Ampolex, Chevron, and Shell, in Block WA205P, 100 miles off NW Australia near the massive, 14 tcf Gorgon Field. Testing is ongoing.
Development prospects do look somewhat brighter, however. Woodside is in the midst of its development of Cossack and Wanaea, and there are signs of other developments from the Timor Gap to the Bass Straits. The Wanaea Field in Carnarvon Basin is expected to begin production, using a floating production system and subsea completions, next year. Nearby Cossack will probably be tied back to it. Together, they hold 180 million bbl oil.
The changes in Australia's tax regime stimulated a bit more exploration, since it allows deduction of expenses before taxes on production, and the much talked about A$15 billion investment program may very well provide the stimulus the industry needs to overcome dependency on imports. The Minerva gasfield in Otway Basin off Victoria is to be developed by BHP Petroleum in a A$300 million program, if the field can get past a barrage of environmental barriers. The 575 bcf reservoir lies only 12 km from the popular Twelve Apostles tourist site.
The Northwest Australian CS is the country's major play for both local and international operators, but several new prospects off southeastern Australia are also drawing interest. Much of this heightened activity is attributable to a new, more favorable policy for both domestic and foreign operators, and most of it has been focused on the vast tracts off Western Australia in the Bonaparte, Carnarvon, and Perth Basins, and on the Bass Straits between southern Australia and Tasmania. And, of course, much of the current enthusiasm for development is due to the already established market for LNG presented by Japan.
Considerable exploration of the Bonaparte Basin has been in Area B of the Timor Gap Zone of Cooperation with Indonesia, where only 50 wells have been drilled so far, but which is expected to become a major venue.
BHP lead all other domestic operators in exploration and drilling activity, and Esso Australia (Exxon) led all foreign companies operating there. Both are involved in developments in the Bass Straits, of Bream B, Turrum, West Tuna, and Yellowtail-South Mackerel Fields.
Ampolex is undertaking a US$1 billion, four-tiered delineation-development program at its Wandoo Field in the Carnarvon Basin. Initial development will cost A$480 million. The field is expected to produce 40,000 b/d.
BHP is active in developing the Griffin Field, the Ramillies Field, Scindian Field, and farther afield in the Timor Sea's Skua Field.
Australia's Bass Straits are set for a boom in exploration drilling this year, according to 50% concessions holder and operator Esso. The company expects to employ four or five drilling rigs in the Straits much of the year. Drilling will be based on 45,000 km of seismic shot since 1992.
Last year, 47 exploratory wells and 18 development wells were drilled. This year's drilling is expected to essentially match that of last year. Operators active in exploratory work include the above as well as Mobil, Petrofina, Preview Resources, Norcen International, Oakman, Woodside, and Kuwait Foreign Exploration Company. And at least 50,000 line-miles of seismic are expected again this year in Western Australia alone.
Acknowledgments: Arthur Andersen, Mackay Consultants, Price Waterhouse, Salomon Brothers, Wood Mackinzie Consultants.
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