1994 OTC SPOTLIGHTS FALL ON TECHNOLOGY, WORLD OPERATIONS

Expanding offshore technical capabilities and growing international cooperation were the keynotes last week at the 26th Offshore Technology Conference (OTC) in Houston.

Sponsored by the Society of Petroleum Engineers, sessions heard many of the 244 technical papers presented this year focus on field ready technology considered crucial to more efficient, safer, environmentally sound offshore oil and gas operations.

Economic development of satellite and marginal fields was the topic at special technical sessions on the conference's first two mornings. Three dimensional seismic technology was thoroughly discussed in a day long series of papers presented during the gathering's third day.

OTC 1994 topical luncheons included descriptions by Shell Offshore Inc. of its record setting Auger field development project in the Gulf of Mexico, offshore turnkey drilling by a panel of drilling contractors, and the international exploration and production alliance formed in 1990 by BP Exploration and Den norske stats oljeselskap AS.

Sec. Gen. Subroto of the Organization of Petroleum Exporting Countries delivered a keynote address outlining OPEC's view of world offshore oil and gas issues (see p. 22).

OFFSHORE COOPERATION

Among announcements at OTC reflecting increasing international cooperation on global offshore oil and gas activity:

Azerbaijan state oil company Socar and a unit of McDermott International Inc., New Orleans, ratified two early April joint venture (JV) agreements with a signing ceremony at an OTC press conference featuring Akhmed Zeinalov, Socar vice president of construction, and William L. Higgins, McDermott executive vice president and group executive of McDermott Azerbaijan Marine Construction Inc. MacShelf JV is to provide turnkey engineering, procurement, and offshore and onshore construction services in the Caspian Sea region, while MacDock JV will repair, upgrade, and maintain offshore vessels and drilling rigs.
Conoco (U.K.) Ltd. and Brown & Root Energy Services disclosed a long term partnering agreement under which the latter will provide life cycle engineering support services for Conoco's existing and future facilities in the U.K. North Sea. As an integrated team, Conoco and Brown & Root expect to lower Conoco's overall costs to develop, maintain, and operate its North Sea assets.
Petroleo Brasileiro SA (Petrobras) announced plans to sign a deepwater technology agreement May 13 with an alliance of BP Exploration and Statoil and shortly thereafter a similar agreement with Shell Oil Co. Petrobras also unveiled a deepwater wildcat discovery in the Campos basin and start of production from yet another record water depth.
Tim Eggar, U.K. energy minister, outlined three new licensing rounds for the U.K. sector of the North Sea.

In the 15th round this autumn, blocks awarded will focus on fast track opportunities that can prove up gas reserves to take advantage of the U.K.'s move toward a deregulated gas market. For the 16th round, also this fall, the U.K. will begin accepting nominations for blocks on both sides of the U.K. The 17th round will focus on frontier blocks.

Eggar said U.K. gas production was up 17% and oil production up 6% in 1993. U.K. reserves in 1993 increased faster than production depleted them.

KEY TO ECONOMIC HEATH

Meantime, an OTC press conference panel representing U.S. service companies, oil field suppliers, and equipment manufacturers agreed that international offshore oil and gas activity is the key to sustaining the health of and employment in the U.S, petroleum industry:

Joseph H. Netherland, chairman of the Petroleum Equipment Suppliers Association (PESA) and vice president of FMC Corp.'s energy and transportation group, said that given the prevailing economic and political factors, U.S. service and supply companies must open new markets for U.S. made oil field products.
James C. Day, chairman of the National Ocean Industries Association (NOIA) and chairman, president, and chief executive officer of Noble Drilling Corp., Houston, said NOIA supports efforts in the U.S. to curb accidental oil releases and minimize effects of such spills. But, Day said, implementing the U.S. Oil Pollution Act (OPA) of 1990 with regulations currently proposed would seriously undermine competitiveness of many offshore oil companies by forcing most U.S. offshore producers out of business.
Robert E. Rose, chairman of the International Association of Drilling Contractors (IADC) and president and chief executive officer of Diamond Offshore Drilling Inc., Houston, said OPA regulations and other pending environmental protection measures are a looming financial injustice to U.S. offshore oil and gas exploration and production. Independent operators, who account for most activity in the Gulf of Mexico, would be especially hard hit, he said.

PETROBRAS OPERATIONS

Joao Carlos de Luca, Petrobras director of exploration and production, reported that his company this year through April drilled five Campos basin discoveries, including the most recent: wildcat No. 495, in 1,053 m of water 130 km from the coast and 5 km east of giant Barracuda field.

Petrobras estimates recoverable reserves of 150 million bbl with this well having a production capacity of 3,000 b/d of oil. Combined recoverable oil reserves of the other four discoveries including one giant field are estimated at 1 billion bbl.

Carlos de Luca said Petrobras on Apr. 29 placed on stream its 4 Marlim well in 1,027 ft m of water in the Campos basin, allowing the company to claim yet another round of deepwater production records. The well, which recently produced 6,466 b/d of oil and 4.45 Mmcfd of gas, was brought on line at a cost of $25 million, an ultimate production cost estimated at $3.47/bbl. The average cost of Campos basin production is slightly less than $10/bbl, he said.

Petrobras kept costs low on 4 Marlim by using recycled equipment and existing infrastructure of the Marlim pilot system.

Petrobras expects the well to maintain pressure for some time, proving the technical and economical feasibility of production in extremely deep water.

The company expects to finish installing the rest of the Marlim system by the end of the month. The first unit of the Marlim Phase I system, the newly built production semisubmersible Petrobras XVIII, is anchored on location in 910 m of water. The $272 million Petrobras XVIII is the world's largest production semisubmersible.

Carlos de Luca said the first of 28 guidelineless wet tree completions is under way and should be on stream soon.

When all the Campos wells are on stream by the middle of next year, production is expected to peak at 100,000 b/d of oil and 3.25 million cum/day of gas.

Petrobras recently opened its oil equipment and services market. Most of its major contracts are now open for international bids.

The next bid order will be for three production semisubmersibles to continue development of Marlim field. Petrobras wants units similar to the XVIII, capable of producing as much as 100,000 b/d of oil in 1,000 m of water.

Two of the units will be new, while one will be a semisubmersible drilling rig converted to production service. The two new units will be a lighter and less expensive design. Petrobras expects the three units to cost $500 550 million apiece and has calculated another $500 million to develop each system for a total of $2 billion.

Petrobras estimates combined peak oil production of the three systems at more than 250,000 b/d with a payout in less than 3 years.

SHELL IN DEEPWATER

In a keynote speech reviewing deepwater production for 1950 2000, F.P. Dunn, Houston, a former Shell Oil Co. executive, pointed out that fixed platform deepwater technology is mature, and major advances are unlikely that would allow fixed structures to be competitive in water deeper than 1,400 ft.

Dunn noted that 1964 72 was the most active for platform technology development, because:

During that time large areas then considered to be deepwater greater than 600 ft were opened to leasing.
Drilling became possible in such depths.
Three large hurricanes spurred interest in soil and metal mechanics for offshore structures.
The computer appeared on the scene.

The period after 1973 represents the maturing of the offshore industry, he said.

Of particular significance after 1973 was the successful design and installation of two platforms: Hondo in 840 ft of water off California and Cognac in 1,025 ft of water in the Gulf of Mexico. Dunn said designs of Hondo and Cognac involved sophisticated fatigue and dynamic analyses, advanced tubular joint analyses and designs, closer fabrication tolerances than ever before achieved, and far more detailed installation engineering studies than previously performed.

FUTURE PLATFORM TRENDS

Dunn said a current important area of development and one likely to become more so is repair and refurbishment of platforms.

Areas in need of improvement include determining platform residual strength, underwater wet welding at depths, techniques for replacing or restoring damaged platform members, and strengthening of substandard platforms.

Compliant towers, which borrow some fixed platform technology, are technical and economical candidates in water as deep as 3,000 ft, he said. Yet Dunn said such towers are relatively "dumb" structures, involving no special operations or maintenance considerations.

Unlike floating structures, compliant towers are insensitive to high deck loads and would therefore be useful as multiwell platforms that also could serve as central facilities for satellite fields.

Regarding other solutions for deepwater development and production, Dunn said:

Semisubmersible based production systems are candidates for deepwater development, but more work is needed on riser systems and anchoring systems to ensure long term reliability.
For tanker based systems, gas disposal, high pressure swivels, risers, and long term reliability of the mooring system must be considered.
Tension leg platforms remain too expensive and complex for use in water depths much greater than 10,000 ft.
Spars can be used as catenary or tension moored drilling and production structures and for storage. The main problem with spar production systems is poor economics, not lack of technology.

NORTH SEA PARTNERING

The North Sea's evolving business climate and maturity as an oil and gas province are reshaping the ways operators and contractors must interact to improve recovery from existing fields and make marginal fields viable producers.

The Conoco Brown & Root partnering contract builds on a relationship formed almost 2 years ago to modify and enhance Conoco's U.K. field operations. It is a nonexclusive engineering services agreement structured to include project development and operation.

By following principles of safety, teamwork, technical expertise, and continuous improvement, the contract is expected to provide seamless, cost effective services from any Brown & Root location to support the business needs of each Conoco U.K. asset.

Conoco's Gary Merriman said cooperative project management will help eliminate duplication of tasks, while greater simplicity of engineering design will reduce costs long term.

"By better matching facilities to reservoir characteristics, we can optimize production, reduce cycle time, and move toward standard designs and components," Merriman said.

Joint Conoco Brown & Root teams in November 1993 began preliminary engineering on facilities for the Conoco operated Jupiter field development project in about 100 ft of water 12 miles southeast of Lincolnshire Offshore Gas Gathering System in the southern U.K. North Sea. Jupiter partners are operator Conoco with a 20% interest; Superior Oil U.K. Ltd., an affiliate of Mobil North Sea Ltd., 50%; BP Exploration 25%; and Statoil (U.K.) Ltd. 5%.

NORWAY'S OFFSHORE OUTLOOK

Gunnar Myrvang, Norway's deputy minister of industry and energy, outlined for an OTC breakfast meeting the five major trends the country assumes in its planning:

A peak in oil and NGL production in 1996 at 2.8 million b/d, followed by a production plateau with a small dip until the turn of the century then a decline.
A decline in oil related investments from the peak of 55 billion kroner ($7.7 billion) in 1993. The decline, however, will not be too dramatic, merely returning to levels of 30-40 billion kroner that were invested in the years before the peak.
An increase in natural gas production that will double Norway's flow from 30 billion cum/year in 1993 to 60 billion cum/year during 2000 10.
An emphasis on developing smaller fields. Reserves of fields under development at present are about 40 million tons of oil equivalent (TOE), compared with the 90 million TOE in fields on stream now. In the next stage of development, Norway's offshore fields will average about 20 million TOE.
A major decrease in field development costs.

Myrvang said Norway as a high cost producing area must cut its field development costs 40 50% during the next 5 years.

STATOIL NORNE CONTRACT

Statoil reported signing a contract with Kongsberg Offshore to provide five four well, diverless, subsea templates for its Norne oil discovery off Norway. Kongsberg Offshore is a subsidiary of FMC Corp., Houston.

Norwegian government approval to develop Norne is expected this year. Norne, in the Norwegian Sea, is Norway's northernmost proposed field development project. Norne production is expected in 1997.

Norne subsea diverless templates are to take advantage of a standardized design used in 10 templates for Statoil's North and East Statfjord fields, Statoil's Sleipner/Loke, AS Norske Shell's Draugen, and Norske Conoco AS's Heidrun fields. Each design allows for four wells, oil production or water injection, and subsea equipment that is highly standardized.

Because of the standardized design, new subsea equipment running tools will not have to be built for Norne. Statoil said Norne subsea equipment will cost $120 million dollars, or about 30% per template less than the first installation of this design in the Statfjord satellite projects.

The subsea wells will flow to a floating production/storage vessel designed to handle about 160,000 b/d of oil from 10 wells. Statoil said Norne's best wells can produce as much as 25,000 b/d, with ultimate recovery estimated at 440 million bbl of oil.

HIBERNIA COST OVERRUNS

Bob Kimberlin, president of Hibernia Management & Development Co. Ltd., told OTC cost overruns on the Hibernia gravity base structure (GBS), the largest construction project in North America, still are being assessed. The original estimate of $5.2 billion (Canadian) could increase 10-20% for the oil field development project off Newfoundland.

Kimberlin said missing the 1996 weather window by 2 months will delay tow out to the production site by 10 months. Tow out is now scheduled for 1997. The weather window off Newfoundland extends from about mid May to the beginning of August.

Hibernia's concrete base, being built at Bull Arm, Newf., has reached 31 ft. Upon reaching 62 ft, the site will be flooded and the concrete base floated out to a deepwater construction site. Hibernia topside modules are under construction at Bull Arm and in South Korea and Italy.

Kimberlin said the 10 month delay in Hibernia's tow out will decrease the amount of construction at the production site and therefore save some costs.

An oil price of $13 15/bbl is needed for the project to break even, but Kimberlin said development of Terra Nova field and other discoveries off eastern Canada will help the long term economics.

Hibernia interest owners are Mobil Oil Ltd. 33.125%, Chevron Canada Resources Ltd. 26.875%, Murphy Atlantic Offshore Oil Co. 6.5%, PetroCanada 25%, and the Canadian government 8.5%.

CREATING GLOBAL OPPORTUNITY

PESA's Netherland cited recent U.S. ratification of the North American Free Trade Agreement (Nafta) and the decision to restore U.S. trade with Viet Nam as examples of actions U.S. political leaders can take to support efforts by service companies and suppliers to prosper and preserve jobs in the U. S.

PESA estimates Nafta could help create as many as 3,000 U.S. jobs in its first year. Similarly, Viet Nam has allocated $400 million to buy petroleum equipment.

Remaining competitive internationally has become more important for U.S. companies because domestic opportunities remain constrained. Despite rebounding activity in the Gulf of Mexico in response to higher gas prices, the combination of low oil prices and reluctance by the federal government to allow tie petroleum industry access to some parts of the U.S. OCS or the Coastal Plain of the Arctic National Wildlife Refuge mean "opportunities in existing domestic markets will continue to be limited." As a result, U.S. companies must either continue shrinking or seek new customers in non U.S. markets.

Netherland said, "The U.S. petroleum equipment, service, and supply industry has the high quality products to compete in the international marketplace. PESA urges Congress and the administration to take additional steps so the U.S. can maintain its world leadership in the oil field service and supply industry." To support U.S. companies competing for international markets, Netherland called for the U.S. Congress to ratify the General Agreement on Tariffs & Trade (GATT), continue promoting a free market economy in Russia and other former Soviet countries, and renew China's most favored nation trading status with the U.S. Netherland asserted that members of the U.S. oil field service and supply industry are consolidating and integrating as they seek new markets and customers overseas.

"Orders create jobs and customers generate orders," he said. "Opening new markets and accessing new customers will enable our industry to maintain its technological quality and competitive leadership throughout the world."

PROBLEMS WITH OPA

NOIA's Day said parts of rules proposed for implementing OPA are written so broadly as to cause many unintended, harmful side effects. The requirement that all offshore facilities carry $150 million certificates of financial responsibility to assure proper cleanup of oil spills drew most of his criticism.

Day argued that the $150 million certificate of responsibility would far exceed the cost of cleaning up individual spills and associated damage.

"According to MMS," he said, "cleanup and associated damage costs from a single offshore platform or pipeline spill on the OCS since 1969 have not reached the current level of $35 million of required financial responsibility."

What's more, if some OPA definitions were strictly interpreted, the financial responsibility requirement would apply in many situations having nothing to do with offshore oil and gas exploration and development.

For example, based on facts that Washington, D.C., formerly was a swamp, the area between the Capitol and Lincoln Memorial was once a canal, and the Capitol in winter is heated with products that could have come from the OCS, Day said one could argue the Capitol should be subject to the same $150 million responsibility requirement as U.S. offshore installations.

"Given the U.S. federal budget deficit, I don't think the federal government would be able to self insure to provide the required certificate, just as most companies working offshore are unable to provide the required certificate," he said.

Day said placing such a heavy burden on the U.S. offshore oil and gas industry would undermine its potential benefits to the domestic economy, hasten the demise of oil and gas activity in the U.S., and lead to still higher spending on oil and gas imports.

"The administration of President Bill Clinton repeatedly has stated it is in favor of increasing the use of gas," he said. "Given this desire, it doesn't make sense to cripple the industry that produces from the nation's premier gas province: the Gulf of Mexico. "

IF IT AIN'T BROKE

IADC's Rose warned that the Gulf of Mexico Initiative (GMI) included in pending federal clean water legislation would further fetter U.S. offshore exploration and production without generating real benefits.

If history is a guide, elevating the Environmental Protection Agency to a position as lead agency overseeing federal offshore oil and gas activity "would lead inexorably to unnecessary, nonproductive, and expensive regulations," he said.

Rose compared the likely effect of GMI to that of the Great Lakes Initiative (GLI), which began in 1989 as a voluntary effort to develop uniform rules to protect the environment of the Great Lakes, only to be enacted into law a year later. A study by DRI/McGraw Hill found GLI won't greatly improve water quality of the Great Lakes, he said, but will require companies to spend about $2.3 billion to comply.

Strong activity in the Gulf of Mexico would help relieve pressures caused by low oil prices in offshore drilling provinces around the world, Rose said. But GMI would undermine job availability and economic prosperity. Because U.S. offshore producers consistently have shown the ability and willingness to operate safely and in an environmentally friendly manner, Rose maintained such excessive environmental rules aren't needed in the gulf.

"The proposed GMI is a solution to a problem that doesn't exist," he said. "If it ain't broke, don't fix it.