Deepwater hotspots, offshore gas transport advances top OTC agenda

High test rates have characterized some shelf deep gas completions, and flow rates in new reservoirs seem to be a function of reservoir depth. The number of shelf wells drilled below 15,000 ft has averaged only about 65 wells/year the past 10 years, lamented Chris Oynes, MMS gulf regional director, speaking at a luncheon address.

The shelf's vast infrastructure can help hold down the costs of deep gas projects, but much of it is aging. The older structures will be the subject of new MMS scrutiny, Oynes said.

The MMS also released new gulf oil and gas production projections through yearend 2007.

Shelf deep gas

The gulf produces 25% of US gas, and the volume produced on the shelf has declined to an estimated 3.36 tcf/year in 2002 from 4.76 tcf/year in 1997.

Since 1993, no more than 86 wells have gone below 15,000 ft in a single year. Compared with 86 deep wells in 2000, operators drilled only 75 in 2001 and 64 last year.

Of the deep wells drilled in 2001 and 2002, only 77 were completed at some depth in the well. MMS points out encouraging test rates from some of the deep completions, however.

Flow rates in new reservoirs tended to be higher the deeper the completed wells went below 15,000 ft.

At 15,000-15,999 ft TVD subsea, the average maximum rate for 20 completions in 2001-02 was 13.8 MMcfd, and none exceeded 25 MMcfd.

At 16,000-16,999 ft TVD ss, 12 completions had an average maximum rate of 32.2 MMcfd. One tested nearly 80 MMcfd, and three others exceeded 50 MMcfd. At greater than 17,000 ft TVD ss, 13 completions had an average maximum rate of 44.8 MMcfd. Two of the 13 tested at more than 100 MMcfd, and four others exceeded maximum test rates of 50 MMcfd.

Another example of excellence in that MMS cited for shelf deep gas fields is South Timbalier Block 204. El Paso Production Co., Houston, discovered the field in late 2000 and placed it online in 2001, MMS said. Production in 2002 was upwards of 350 MMcfd of gas plus condensate.

Other shelf deep gas finds in 2003 include JB Mountain in federal waters of South Timbalier and Mound Point in state waters off Louisiana, MMS said.

A federal royalty holiday for gas produced from new shelf leases has helped draw some majors, including BP PLC, ChevronTexaco Corp., and Royal Dutch/Shell Group back to the shelf, at least for targeted prospects, Oynes said. MMS has proposed to extend royalty relief to existing leases.

Fit for purpose

One efficiency of shelf operations, existing infrastructure, is complicated by facilities age, Oynes noted.

Of more than 4,000 platforms in the gulf, 853 are 20-29 years old, 642 are 30-39 years old, and 310 are 40 years old or more.

"We are going to certainly be vigilant in working with companies on what facilities can be reused or continue to be used," Oynes said.

An MMS proposed rule issued on Apr. 21 incorporated the 21st edition of API Recommended Practice 2A, of which two chapters are relevant to aging infrastructure. RP 2A contains guidelines for evaluating the fitness for purpose of existing but aging structures and structures proposed for uses different from those for which they were designed.

Deepwater action

Many large discoveries in very deep water in 2002 fueled more deepwater activity.

Industry has brought 65 deepwater fields on production through yearend 2002, and 18-19 more will go online in 2003 and 15 more in 2004.

Around 60% of the total gulf's oil and 30% of its gas come from fields in 1,000 ft of water or more, based on 2001 figures, Oynes said.

"Exploration on a broad scale is starting to unfold" in the eastern gulf, he noted. Operators have filed 14 exploration plans with MMS for blocks leased in December 2001. Florida has given coastal zone consistency approval to 8 of the 14.

Most of the leases awarded from that sale are in 7,500 ft of water or more.

MMS tentatively scheduled another eastern gulf lease sale for Dec. 10.

Total Gulf of Mexico oil production should rise to 1.58-1.93 million b/d by yearend 2007 from 1.01 million b/d in 1996, according to MMS projections released May 5.

Gas production should reach 9.86-12.51 bcfd by yearend 2007 compared with 13.9 bcfd in 1996.

MMS made the projections based on information submitted by 20 gulf operating companies. The oil figures include condensate, and the gas totals take in nonassociated and associated gas.

Shuttle tanker use in gulf

Shuttle tankers would provide an alternative to pipelines as a way to transport oil from offshore platforms to refineries, panelists said. No shuttle tankers currently exist in the gulf, and they would have to be built in the US under the Jones Act and must have a doublehull to comply with the Oil Pollution Act of 1990.

Houston-based American Shuttle Tankers LLC (AST) is in discussion with the majors and many independents regarding the use of a separate storage vessel and a shuttle tanker, said Peter Lovie, the firm's vice-president of business development.

Speaking to reporters after a news conference, he said a producer could make a commitment within a year to agree to use American Shuttle Tankers as a transportation contractor, and that it would take 2-3 years before a shuttle tanker could be built and put into service in the gulf.

The US Minerals Management Service is contemplating the potential of shuttle tankers in the gulf as a way to transport crude oil through its royalty-in-kind payments, confirmed Milt Dial, MMS assistant program director, RIK minerals revenue management.

"We will explore all reasonable methods of lowering transportation costs involved in royalty asset sales. Shuttle tankering may be one of those options. We are on the front-end of discussions," about that, Dial said.

PFC Energy, a Washington-based consultant, believes that the gulf will have excess transportation capacity in 3-5 years in areas where the infrastructure is well developed, said Mike Rodgers, PFC upstream group senior director of the exploration and production portfolio and business development unit.

But Rodgers noted that some areas have less infrastructure, particularly in some of the deepwater exploration areas where companies increasingly are now shifting their focus.

Shuttle tanker logistics

AST is owned equally by Skaugen PetroTrans Inc. of Houston and Navion ASA of Stavanger. Skaugen provides lightering services in the gulf, while Navion operates a fleet of shuttle tankers in the North Sea.

Lovie said the economics of crude oil transportation by shuttle tankers compared with pipelines would vary on a case-by-case basis, and he declined to give any specific examples or model projections.

A gulf shuttle tanker would have 565,000 bbl of oil capacity, while a separate vessel would have a 750,000-800,000 bbl capacity, Lovie said.

"Shuttle tankers can work with any floating production installation: semisubmersibles, spars, tension leg platforms, and floating production, storage, and offloading vessels," he said.

The advantage of shuttle tankers is that they can serve any floating production unit and can go to any port that the producer desires.

Producers would enjoy freedom to sell their crude for the best price, freedom for each production hub partner to sell its production separately, and freedom from quality bank penalties, Lovie said.

Crude oil from various sources is commingled in a pipeline, but oil put into a shuttle tanker would not be commingled with oil from other producers, Lovie said.

He envisions a field using multiple shuttle tankers plus one storage vessel adjacent to the platform. Several storage vessels exist already, he said.

IOC concerns about Brazil

In addition to their disappointment in exploratory results off Brazil, IOCs fear that an increasingly onerous fiscal and regulatory regime will squelch what remaining lure the country has for future exploration and development investment.

That consensus view was delivered by three executives each representing IOCs active in Brazilian E&D in presentations at the opening session of OTC.

The message was a sobering one for a country whose E&D investment opportunities, particularly in the deep water, have been among the world's most highly touted in recent years. The three executives pointedly noted that Brazil risks losing out in the competition for foreign E&D capital to the world's other two leading deepwater hotspots, West Africa and the US Gulf of Mexico.

Disappointing results

IOCs' disappointment with E&D results from the frenzied activity of the first 5 years of a monopoly-free upstream sector in Brazil does not stem from lack of exploratory success in geologic terms, according to Stephen P. Thurston, with ChevronTexaco Overseas Petroleum Inc. (COPI)

Indeed, operators drilled 59 wells that were geological successes out of 122 total drilled in the so-called Brazil salt basin (comprising the Campos, Santos, and Espirito Santo basins) from September 1998 through 2002.

But only two of those have been declared commercial successes, said Thurston, who coauthored a paper on Brazil's evolving deepwater risk-reward profile with COPI's Thomas R. Bard.

The lack of commerciality stems from the fact that the Brazilian discoveries have been poorer than expected in terms of reserves and in terms of crude quality—shortcomings magnified by their occurrence in deep water.

The 57% exploratory well geologic success rate notwithstanding, the commercial success rate for the postmonopoly period was a paltry 2%, Thurston noted, compared with 30% and 16%, respectively, in the deepwater Gulf of Mexico; a respective 62% and 16-27% for deepwater Nigeria exploration; and a respective 70% and 63% for deepwater Angola. Another 15 finds could mature into commerciality off Brazil, resulting in a postulated 17% commercial success rate, he noted.

Now-diminished expectations contrast sharply with the almost giddy fervor with which foreign operators approached the Brazilian deep water, following a decade marked by a string of giant deepwater discoveries in the Campos basin by Brazilian state oil company Petroleos Brasileiro SA (Petrobras).

In another presentation, Unocal Corp.'s Andrew L. Fawthrop noted that operators investing in Brazilian exploration in the past 5 years expected success rates approaching 30% and field sizes of 500 million-1 billion bbl of oil with gravities of >25º API.

"Except for Petrobras's giant (300-700 million bbl of oil) Jubarte field discovered in 2001, no significant commercial deepwater discovery has been made since the Roncador field in 1996, despite more than 100 wildcat wells drilled since mid-1997," Fawthrop said. "Other, smaller discoveries are not commercial under current fiscal terms."

Fawthrop said that Unocal "expects that future deepwater discoveries in Brazil will beU250-500 million bbl of oil, in water depths of 3,200-6,500 ft, and relatively heavy oil with API gravity below 20º.

Opportunity profile

Thurston compared Brazil's "opportunity profile" today and at the opening of its E&D sector to foreign investment in 1998-99. He made that comparison on the basis of four key elements to sustain an E&D investment: commercial resource opportunities, competitive terms and conditions, stability of terms and conditions, and viability of operating conditions.

That opportunity profile has been diminished not only by the lack of commercial success but also by the fact that "the most likely discoveries" will not be "globally competitive under current fiscal terms," Thurston said. He cited the complexity and proliferation of taxes in Brazil as well as a lack of stability in terms—"harmful fiscal changes made after the concessions were awarded."

Coming in for special condemnation was a tax imposed, just before licensing Round 4, by the state of Rio de Janeiro of 18% on the same list of deepwater production equipment previously exempted from special taxation under a temporary federal tax initiative known as Repetro.

Thurston also called for the government to establish "clear regulatory procedures and policies; a predictable, reliable, and efficient environmental licensing process; and resources dedicated to operational safety and emergency preparedness."

While Brazilian regulatory agencies and the National Petroleum Agency (ANP) made significant progress in this regard last year, he said, there remain concerns over staffing levels in regulatory offices to handle development programs.

And the new Brazilian government's insistence on local content requirements for construction of offshore oil and gas facilities could have a "significant impact," said Shell Brasil Ltda.'s John Haney, in another presentation.

Thurston noted an increasingly cumbersome fiscal and regulatory regime is deflating industry interest in opportunities whose terms were deemed suitable for the kind of higher-crude-quality, bigger-reserves fields Petrobras seemed to find routinely during the 1980s and 1990s, in the core Campos basin area that it continues to dominate.

He cited the disappointing results of ANP's Round 4 licensing tender, held last year, when the average winning bid was only $1,473/sq km vs. $3,500-4,125 in the first three rounds.

"We believe this dramatic change in Round 4 was not a case of the 'full plate syndrome' or simply the quality of the acreage offered, but in fact due to the overall industry changing its perception of the potential resource and commercial opportunities in E&P in Brazil," Thurston said.

Still attractive, but...

Shell's Haney, in a presentation coauthored by the same company's Michiel Koot, offered a critique of the Brazilian investment opportunity similar to those of Thurston and Fawthrop, while averring that his company "still sees Brazil as attractive," given Shell's "deepwater edge."

"There is no doubt that the opening up of the upstream sector was successful," Haney said, citing the involvement of more than 40 investor companies, expenditure of more than $1 billion for exploration alone, acquisition of 320,000 line km of 2D seismic and 120,000 sq km of 3D seismic, and drilling of some 200 offshore wells.

"However, the offshore exploration results since the opening of the sector have had mixed results. Some 110 technical discoveries have been reported, but most are believed to be small to modest-size accumulations of generally low-gravity crude oil or gas," he said.

Haney noted that "technology is key" to unraveling much of the concern over commerciality of the Brazilian discoveries, marked as they are by complex geology and hydrocarbon systems, low gravities, and dispersal of reserves.

But just as important is a government willing to offer relief from increasingly onerous fiscal terms, he contends.

"New taxes may be seen as insignificant by those imposing them, but taken together, they tend to erode an already marginal investment." Haney said.

More drilling ahead

Thurston also noted that the full extent of the first exploratory drilling efforts off Brazil has yet to be realized, with all of the wells drilled and discoveries made thus far from a "preliminary" round in 1998—the so-called ANP Round 0, which mainly entailed offerings of Petrobras farmouts and relinquished acreage. Round 1 was held in 1999, Round 2 in 2000, and Round 3 in 2001; Round 5 is slated to be held this August.

He predicted that drilling activity on the Round 1 blocks will increase substantially in 2003-04 as they make the transition from the primary seismic period to first exploratory drilling. Subsequent rounds will yield similar flurries of drilling activity. However, a surge in the number of farmout opportunities and acreage relinquishments points to an increasing risk profile for the Brazil salt basin. And given the increasing competition for E&D capital, there is a narrowing window of opportunity for operators to make investment decisions on their Brazilian portfolios.

Thus the country's worsening risk-reward profile should compel the government to reconsider soon its fiscal terms governing deepwater E&D.

It all adds up to a situation where "the risk has gone up, while the reward has gone down," Thurston said.

Caspian Sea production

The Caspian Sea region still has some obstacles to overcome before becoming a major contributor of non-OPEC oil supply growth in coming years, panelists agreed.

A US Energy Information Administration spokesman said the Caspian region currently produces 1.5 million b/d of total liquids. W. Calvin Kilgore, director of EIA's office of energy markets and end use, also cited estimates of proved reserves under the Caspian Sea and in the surrounding coastal areas, excluding Russia and Iran, of 17-33 billion bbl. Numbers vary widely depending upon the source, he said.

Kilgore said his office predicts that Caspian production will reach 3.4-4 million b/d of total liquids by 2015.

EIA recently forecast that the Organization of Petroleum Exporting Countries will produce nearly 56 million b/d by 2025, compared with current production of 27 million b/d.

Meanwhile, Russia's oil production is expected to start falling off after 2015, while the Caspian Sea region is expected to show major incremental increases during 2020-25 in both oil and natural gas, Kilgore said.

US energy policy

Candy Green, international energy officer for the US Department of State, said US energy policy regarding the Caspian Sea region during the 1990s focused on transportation issues. Progress has been made on pipeline route issues, she said, adding, "That does not mean that all the problems have gone away."

Regional challenges still include the need for respecting contracts, strengthening democracy, transparent management of oil and gas earnings, and the curtailment of corruption, Green said.

"We all win when transparency and free markets prevail," Green said, adding that development of the Caspian Sea region's reserves and infrastructure hinges upon financing. The region needs $10-12 billion in 3-5 years for oil field services alone, she said.

Regarding Russia, Green said the US government sees "merit in involving the private sector in Russian pipeline development." Russia is expected to issue a report regarding its pipeline development later this month, she noted.

"Russia will need to allow competition in gas transportation," Green said. "We continue to see room for improvement in the investment climate."

Overall, billions upon billions of dollars worth of investments are needed to tap into Russia and the Caspian Sea region's energy potential, said Amy Jaffe, senior energy advisor to the James A. Baker III Institute for Public Policy of Rice University.

"Companies that want to go to capital markets will have to exhibit transparencyU. It's the need for capital that will drive the end of corruption," Jaffe predicted.

Corporate policy

Thomas Knudson, ConocoPhillips senior vice-president of government affairs and communications, said the world needs the Caspian's resources, and in turn, the Caspian region needs more private investment.

In the past 3-4 years, public oil and gas companies have shifted their primary focus from building production volumes to trying to ensure predictable earnings and quality returns for shareholders, Knudson said.

Oil and gas companies are looking to create legacy assets while seeking stable, predictable, and transparent fiscal and tax regimes. This is true regardless of whether the project is in the Caspian Sea, the North Sea, or the Gulf of Mexico, he said.

In its quest for legacy assets, ConocoPhillips also looks for market-driven development prospects having secure, dependable transportation options, he said. ConocoPhillips will not develop giant fields unless it also sees viable markets and a means of reaching those customers, he said.

ConocoPhillips has a stake in giant Kashagan oil field in the Caspian Sea. Kashagan is expected to begin producing in 3-4 years (OGJ, Mar. 17, 2003, p. 42).

Stranded gas recovery

Worldwide there is more than 200 tcf of stranded gas that is out of the economical reach of pipelines, said Al Kaplan of Arup Energy, the offshore engineering unit of Over Arup & Partners, London. That gas is awaiting recovery via the development of such innovative facilities as:

• Floating gas production, storage, and offloading vessels (GFPSOs) for recovering and processing natural gas, then storing and offloading it in the form of LNG or compressed natural gas (CNG).
• Floating concrete substructures designed for offshore LNG production and storage.
• Offshore LNG regasification facilities and subsea storage in salt domes.
• CNG shipping vessels.

"Last year there was talk of developing 5-20 new [LNG] terminals in the US," said William Sember, vice-president of offshore development with the American Bureau of Shipping [ABS]. "These are a number of locations that are becoming more developed, and the possibility is becoming very real," he said. "In the US there are two applications that have been filed: one by ChevronTexaco Corp. [OGJ, Dec. 9, 2002, p. 8] and the other by El Paso Corp. [OGJ Online, Dec. 26, 2002].

Sember was one of a panel of seven speakers at a press conference who was to present technical papers May 7 at a panel session on gas transportation and offloading showcasing offshore LNG and CNG facilities and processes.

Sember said drivers for LNG development include a continuing demand for clean-burning fuel and concerns about long-term US gas supply, both of which have increased the need to secure these reserves. "LNG infrastructure costs today are lower than they were a decade ago," he said, and safety and security concerns about locating LNG facilities in populated areas are prompting the industry to find offshore LNG terminals more attractive as an option.

"[These options] will be a fact of life 4-5 years from now," agreed Jaap de Baan of Bluewater Energy Services BV.

GFPSOs

"The concept of a GFPSO is technically and commercially feasible," said Jan Wagner, technical director for Fluor Canada, "And there are technically proven options available for production of stranded dry gas reserves." GFPSOs could be moved from one field to another to recover and process associated gas or remote gas reserves. The vessel essentially would be a floating gas production and conditioning facility, with its principal export products liquid LPG and condensate and pipeline quality residue gas.

"Transport of the residue gas remains the biggest problem facing implementation of a GFPSO," Wagner said. He said the gas could be transported or readied for transport by one of four generic methods:

• By pipeline in the gas phase.
• Gas volume reduction through liquefaction or compression.
• Conversion of natural gas to another form of energy such as electric power and exporting it via subsea cable.
• Gas-to-liquid conversion of the "methane molecule" to a liquid such as methanol.

Wagner said the pipeline and LNG options tended to show a tradeoff beginning at a distance of about 2,000 km from the market.

"CNG appears to be the best option [economically], but we don't have a commercial application to date," Wagner said after comparing the four options. The CNG option "demonstrates the lowest overall investment for the operator," he said, but only on the assumption that CNG ships are available. "Since none of these ships has yet been built, the economics of the initial CNG projects will reflect the capital costs of the ships in some manner."

"A GFPSO project can be expected in the not-too-distant future," Wagner said.

John Dunlop of Enersea Transport LLC agreed, saying that Enersea, its strategic partners, and ABS over the past year have worked to develop and verify "the world's first" safe, practical ship design for a CNG marine transport system, which Dunlop said is now ready for commercialization.

The proposed CNG ships, with projected capacities of 525 MMscf-1 bcf, are called volume-optimized transport and storage gas handling (Votrans) vessels. Dunlop said the Votrans contain complete, "wall-to-wall" production facilities that can process both rich and lean associated gas and gas in risky areas and in deep water with a 60-100% increase in gas storage efficiency.

"LNG requires 2-3 times as much energy per unit of energy delivered [through liquefaction, boil-off, and regasification] compared with CNG and pipelines," the partners said. "But CNG ships are more costly per unit of gas transported compared with LNG ships, because the cargo density is low, so CNG transport schemes are conceived to keep the ships at sea, without entering ports," to minimize round trip cycle time.

Dunlop said the vessels would be useful for producing stranded gas reserves in locations off Newfoundland and Latin America and in the Caribbean. The flexibility of moving to a new location after a field is exhausted is a great benefit, he said.

Offshore LNG terminals

Nearshore and offshore LNG terminals comprise a marine transfer system in combination with a regasification plant and a salt dome storage cavern. Although the concept is new, all components used are already proven and have been applied in LNG terminals and offshore loading systems for a long time, De Baan said, and design work to date shows that the transfer system, regasification, and salt cavern-based storage options are fully feasible.

Offshore and nearshore LNG terminals fill a need for the supply of LNG—the fastest-growing hydrocarbon fuel—when conditions are unfavorable for onshore terminals. The most dominant advantages of LNG offshore terminals are the lower costs for construction and operation—no need for dredging—avoidance of congested shipping or mooring concerns and congested ports, and security and cost considerations.

Salt caverns can be solution-mined in less time and about one fifth the cost of constructing cryogenic tanks, resulting in lower capital expenditures and a shorter construction schedule, Bluewater said. Permitting will be quicker as well.

"There are more than 400 salt caverns in the [upper Gulf of Mexico] area," said Mike McCall, president and CEO of Conversion Gas Imports LLC. CGI is participating in a cooperative research project to define, describe, and validate a process to use a salt cavern to receive and store regasified LNG.

"The process involves receiving LNG from a ship, pumping it up to cavern injection pressures, warming it to cavern-compatible temperatures, injecting the warmed vapor directly into salt caverns for storage, and distribution to the pipeline network," CGI said.

Bluewater said it has developed a whole suite of LNG transfer-option concepts, including tandem, side-by-side, and single-point mooring system transfers to accommodate variances in water depth and environmental conditions, but all concepts share a common philosophy, the company said.

"Very few energy companies apply sufficient resources to solving 'tomorrow's' problem," De Baan said. He said he wanted to "provide the LNG industry with insight and confidence that mooring and fluid transfer technology as applied to the 'oil industry' also applies to their business."

CFPSOs studied

As governments and operators research the potential of floating LNG production facilities, they are investigating FPSO hulls made of concrete (CFPSOs) as well as hulls of steel.

"Both are viable," Kaplan said. The concrete structure would be used for liquefaction application, not as a terminal, he added. "However, [the use of concrete] requires a substantial amount of work before it comes to the fore," Kaplan said. One of the biggest challenges associated with floating concrete FPSOs for natural gas production and storage, Kaplan said, is designing the loading systems.

In addition, "Design codes are not established yet, tankage cost and safety issues need to be addressed, and financial institutions must be satisfied."

However, concrete substructures also offer advantages for the support of cryogenic facilities that are not found on steel structures. The deck area is sufficiently large to allow topside facilities to be configured with some modularization and preassembly, using vendor-supplied skids, and they can be built using locally procured materials and labor.

A concrete structure would be about 200 m wide by 300 m long with tanks in the bottom and processing and offloading facilities on top. Kaplan said. One safety advantage would be the 1 m thick walls that would protect against vessel impact and dropped objects. Superior cryogenic performance would be a plus for concrete as well, as would the superior stability and low motion in extreme environmental conditions due to the structure's wide beam.

A 9 million tonne/year LNG production CFPSO is being developed to support a two-train LNG facility for use at a stranded gas location off West Africa. It is expected to be completed within 43 months of engineering, procurement, installation, and commissioning contract signing, Kaplan said.

New regulatory issues

Important regulatory changes now affect offshore LNG and CNG facilities classification, siting, construction, operation, and maintenance, Sember said.

For example, the Maritime Transportation Security Act of 2002, which President George W. Bush signed last November, amended the Deepwater Port Act of 1974 to include natural gas, fundamentally altering the regulatory process for offshore LNG terminals.

In addition, the US Coast Guard will now share with the US Maritime Administration, rather than the Federal Energy Regulatory Commission, the primary responsibility for regulating these offshore facilities—with other federal agencies and the involved states playing subsidiary roles.

ABA has a liaison with the regulatory agencies and has proposed combining current regulations with classification society guidance to develop appropriate design, construction, and operational requirements for offshore LNG terminals. Such a process, Sember said, may be helpful in expediting regulatory approvals.