BRAZIL'S DEVELOPMENT PLAN CENTERS ON DEEPWATER OIL

Brazil's state owned Petroleos Brasileiro SA continues to advance deepwater technology as it pushes the frontier in ultradeep waters of the Campos basin off Rio de Janeiro state.

Petrobras holds many world records related to deepwater drilling and production. But the Campos basin campaign goes beyond technological bragging rights.

The prolific basin, which accounts for more than half the country's crude oil production, is expected to be the cornerstone of Brazil's plans to boost production to 1 million b/d in 1995 from a record 720,000 b/d at yearend 1993. OGJ estimated average Brazilian oil production at 631,300 b/d for all of 1993, up from about 626,000 b/d in 1992 (OGJ, Dec. 27, 1993, p. 37).

Even with the surge to 1 million b/d, Brazil almost certainly will continue to be a net oil importer. It currently consumes an average 1.375 million b/d of oil. And despite the recent progress in production growth, Brazil is falling short of its earlier targets. Petrobras in mid 1992 projected an average 700,000 b/d for 1992 and 790,000 b/d in 1993 (OGJ, Jul 6, 1992, p. 52).

The missed production targets result not from lack of identified oil reserves or technological capability, both of which Petrobras has in abundance in the Campos basin. The problem is lack of capital in the financially stressed country. Petrobras began reassessing its spending plans in 1992 after projections called for a need to spend about $18 billion on exploration and production to meet the target of 1 million b/d by 1995.

Those plans are being further reassessed as Brazil's government indicates it might slash Petrobras's budget by half this year amid continuing economic turmoil. The funding dilemma also strengthens the case for at least partially privatizing the giant state petroleum concern, a controversial step at best.

CAMPOS SURGE

Petrobras's crude oil production reached a record 710,232 b/d in October 1993.

Production was expected to climb another 10,000 b/d or so by yearend 1993 when Caravelas field in the Santos basin goes on stream, said Joao Carlos Franca de Luca, Petrobras E&P director.

The production record resulted from overall increased productivity in Offshore Campos basin fields, which produced at 97.1% of capacity. That's the highest productivity level in the company's history, de Luca noted. Another factor was the growing role of giant field projects begun in recent years, notably Albacora, Marlim, and Marimba.

Brazilian oil production increased about 10% from October 1992 to October 1993. Meantime, in first half 1993 crude reserves increased by about 4% from the prior year period. Current proved reserves total 4.6 billion bbl of oil equivalent (BOE) in waters to a depth of 1,000 m.

CAMPOS POTENTIAL

If recoverable volumes of oil in water depths at 1,000 2,000 m are taken into consideration, Brazil's reserves total jumps to 11 billion BOE.

At present, Petrobras considers as proved reserves only those located onshore or in water depths of less than 1,000 m. Potential Campos basin reserves in waters deeper than 1,000 m are estimated at 1.5 billion bbl and 1.05 tcf of gas.

Currently, the Offshore Campos basin accounts for 60% of Brazil's production.

From the time Petrobras started up its first Campos production system in Enchova field in 1977 until start up of the Marlim field pilot project in August 1992, Petrobras installed 26 floating production systems (FPSs) and 14 fixed platforms in Campos basin. There are 12 FPSs currently in operation off Brazil.

Three giant oil field discoveries in recent years in the Campos basin led Petrobras to focus greater attention on their future development with an eye to integration and operating efficiencies.

Marlim complex holds proved and probable reserves estimated at 1.7 billion bbl and covers a 156 square km area in water depths of 400 2,000 m. Albacore's 1 billion bbl estimated probable reserves lie in waters of 200-2,000 m covering a 236 square km area. Proved and probable crude reserves in Barracuda field are estimated at 467,435,000 bbl out of original oil in place of 3 billion bbl and are located in 700 1,000 m of water over a 170 square km area.

Meantime, Petrobras drilled a significant Campos discovery near the Marlim complex last October.

The 4 RJS 396D, about 10 km from Marlim in 700 m of water and 100 km offshore, was the 1,000th well drilled in the basin since exploration got under way in 1971. The discovery produced from sands at 2,500 2,517 m. Initial calculations indicate reserves of about 20 million BOE and productive capacity of 3,000 b/d.

Petrobras' success rate for all offshore exploratory wells is 35%. Its success rate is 58% for exploratory wells in more than 400 m of water.

Deepwater and ultradeepwater production is a vital issue for Petrobras. Although only 8% of Brazil's crude oil production comes from wells in more than 400 m of water, that level is expected to reach 61% by 2001, barring any major onshore or shallow water oil discovery.

DEEPWATER RECORD

Another deepwater record is set to fall in April, when Petrobras is expected to complete the 4 Marlim well in a water depth of 1,027 m (3,369 ft).

That will far surpass its current world water depth record for a subsea completion and production in 781 m (2,562 ft) of water with the 9 Marlim well.

The 4 Marlim also offers significant strategic value because it will be the first to produce in the South Marlim reservoir. Because it will be drilled and completed as a satellite tied back to the Marlim pilot system, lifting cost is pegged at only $3.45/bbl, de Luca said.

Commercial production of South Marlim will have a decisive effect on the classification of deepwater reserves by Petrobras. With 4 Marlim commercial, some of those reserves will be reclassified as proved and targeted for production.

Petrobras will spend $25 million to complete 4 Marlim with a guidelineless (GLL) wet christmas tree (WCT) tied back to the FPS that serves as the Marlim pilot system. The FPS, 19 km from the well in 620 m of water, was converted from the Petrobras XX semisubmersible drilling rig and is now called SS 33.

The greatest share of the $25 million outlay, considered low by Petrobras officials, will purchase flexible pipelines and hire lay vessels, remove a GLL WCT from the 20 D Marlim well, and install a WCT, possibly that from 20 D Marlim, in the record well.

Production from 4 Marlim will begin at 7,000 b/d of oil and replace one of the 10 wells currently producing in the Marlim pilot, the poorly producing 20-D Marlim. The 20 D Marlim lies between 4 Marlim and the FPS, thus allowing the use of 6 km flexible pipelines on the seabed and perhaps the WCT if it is in good condition.

The Marlim pilot started up in August 1992, replacing a prepilot system. The pilot includes seven wells in the main Marlim reservoir and three in adjoining reservoirs (see map, OGJ, Dec. 6, 1993, p. 21). Production from each of those wells moves through flexible lines to the SS 33.

SS 33 can process 53,000 b/d of oil and 42 MMcfd of gas.

Oil is exported through the same monobuoy installed in the prepilot system linked to the Horta Barbosa oil tanker, which offloads the crude to other oil tankers. Natural gas is exported to a fixed platform in Garoupa field through a rigid gas pipeline linked to the Albacora Garoupa gas line.

In July, Petrobras expects to operate a gas lift system, but there are no other plans for secondary recovery in this phase of Marlim development.

MARLIM PHASE I

Phase I Marlim field development is divided into two modules. For Module 1, Petrobras plans to convert the Petrobras XVIII semisubmersible to an FPS for installation in 910 m of water.

Module 1 will be able to process 100,000 b/d of crude oil, 147 MMcfd of gas, and 151,200 b/d of injection water. Production will start from 16 wells and water injection through 12 wells. The wells will be completed with GLL WCT linked to the FSP via risers and flexible lines. Production start up is planned for June.

At first the crude will be exported through two 12 in. pipelines from the FPS to a pipeline and manifold (PLEM) in 200 m of water.

From the PLEM, crude wig move through two 10 in. pipelines to two nearby monobuoys and from there by tanker to coastal terminals. In 1997, crude will begin flowing directly to shore through a 105 km, 34 in. pipeline linking the Marlim PLEM to Barra do Furado on the coast of Rio de Janeiro state. From Barra do Furado, Marlim crude will flow via onshore pipelines to the crude oil processing center at Cabiunas. Natural gas will be exported from the FPS to the PLEM through a 10 in. pipeline and then via a 14 in. spur to Platform Namorado 1 for export to shore.

Module 2 is expected to use the Petrobras XIX semisubmersible as an FPS moored in 770 m of water with a nominal capacity equal to the Petrobras XVIII FPS. Production is expected to begin in June 1997. The company also is considering maintaining the SS-33 in its current position.

Thus, Module 2 will include production from 25 wells 16 linked to the Petrobras XIX FPS and nine to the SS 33 with expected capacity of 6,300 b/d/well and water injection through 12 wells at 12,600 b/d/well. All the wells will be completed with GLL WCT and linked with the FPS/semis via pipelines and risers.

Marlim's pilot produces an average 35,000 b/d of oil and 21 MMcfd of gas in water depths of 563 781 m.

ALBACORA BIGGEST PRODUCER

While second in overall reserves to Marlim, Albacora field is Brazil's biggest offshore oil producer at about 57,000 b/d.

Petrobras plans to continue increasing production there and is turning Albacora into what also could be a litmus test of prospects for foreign participation in the opening of Brazil's offshore market.

Albacora was discovered in 1984 with the 1 RJS 297 wildcat in the northeast part of the Campos basin, 100 km off Rio de Janeiro's coast. Albacora is considered a rather complex field with a total of eight reservoirs, of which the most important produce from Oligocene Namorado and Miocene Carapebus.

In keeping with the Petrobras strategy in developing deepwater fields, Albacora is being developed in three phases. Crude to be produced during Phases I, IA, and II features gravities of 26 29. Crude to be produced during Phase Ill has gravities of 18 21.

Albacora also has Brazil's second horizontal offshore well, 7 AB 13H-RJS, which went on stream last June 26. It is in 720 m of water and produces 5,000 b/d of oil.

FOREIGN PARTICIPATION?

Petrobras has called an international tender for bids on what might become a precedent setting turnkey contract for converting a semisubmersible rig into an FPS.

Last Oct. 14, Japanese trading company Nissho Iwai formalized its earlier proposal to finance purchase and conversion of the Petrobras XXV semi, formerly the Zapata Arctic, into an FPS.

De Luca said Nissho Iwai will provide $150 200 million and has asked for an answer from Petrobras by Jan. 15. The FPS, rated to operate in 650 m of water, will be equipped to process 100,000 b/d and 70 MMcfd.

The FPS is expected to start bringing on stream another 27 Albacora wells in 1996. This will be the biggest such conversion job undertaken by Petrobras and probably the biggest anywhere. The only other semi/FPS conversion with a 100,000 b/d capacity involves the Petrobras XVIII, recently undertaken in Singapore by Far East Levingston Shipyards (FELS) for $270 million and now being completed in southern Brazil by local FELS affiliate Tenenge.

Petrobras originally leased the Zapata Arctic from its owner Arethusa through its foreign subsidiary Brasoil. Petrobras has had a number of semis converted for production work in the Campos basin and more recently in the Santos basin, but those conversions were conducted mostly within Brazil.

As a result of a new government policy to open Brazil's market wider to foreign suppliers, and because this semi was first leased by a Petrobras foreign subsidiary and is registered abroad, it doesn't have the legal and bureaucratic restrictions the company's other domestic flag semis have. Thus the Petrobras XXV can be converted in any shipyard.

Most of the FPS conversions until now relied on second hand equipment and material recycled from previous Petrobras projects, but this time the company wants to work on a turnkey basis, which implies use of new separators, pumps, generators, and other equipment. New equipment can often be found at a much lower cost outside Brazil.

However, because the government has not yet approved Petrobras' $3.7 billion capital budget for 1994, the company has not set its timetable for tenders for Albacora or other fields. Petrobras says Albacore's second phase most likely will go on stream in May 1996.

BARRACUDA PILOT

Barracuda field, a 1991 discovery, lies southwest of Marlim in water depths of 700 1,100 m, 100 km off Rio de Janeiro state. It contains 25.6 gravity oil, lighter than the Campos basin average.

The main production system under study for this field will have three production units supporting 103 producing and 28 water injection wells.

At full flow by 2003, Barracuda production is expected to peak at 122,300 b/d of oil and 55.6 MMcfd of associated gas.

To achieve those volumes, Petrobras will first bring on stream a pilot production system to obtain more information about the reservoir. In the pilot phase, 11 production wells will be completed, of which nine have been drilled. More than 35 km of flexible production bundles, 12 km of flexible risers, and 11 WCT also are planned.

Barracuda's production facility will be a floating production, storage, and offloading (FPSO) unit converted from the P.P. Moraes tanker and involving a turret moored, swivel deck, loading system and a processing plant with capacity of 30,000 b/d of liquids and 33 MMcfd of gas.

Petrobras is finishing the basic design and preparing an international tender, scheduled for this month, for the tanker modifications.

The FPSO tanker will be modified to process the oil and offload it to a shuttle tanker. Gas will be reinjected at first and later exported to shore through a dedicated riser and flow line. This pilot system will remain on station for at least 5 years and be classified as a stationary production unit (SPU).

Tenders for contracts totaling $200 million for installation of Barracuda's pilot system in 850 m of water are to be disclosed early this year. They are to include a $30 million contract for the turret system, which is a new technology expected to be supplied by foreign companies, Petrobras officials said. Total contract costs also include installation of all equipment and drilling the 11 wells. The pilot is expected to produce an average 15,550 b/d of oil and 7.3 MMcfd during 1995-2000, with payout and a peak of 33,700 b/d in 1997.

Petrobras is studying whether to use its technology of semi conversions for the final production system or SPUs based on foreign technology.

Petrobras notes that several FPS innovations and some world records will be set when Barracuda's pilot goes on stream. Petrobras will have:

The world's deepest water subsea completion, with the
RJS 381 well, in 980 m of water.
The world's deepest water FPSO, moored in 843 m of water.
The world's largest turret design tanker loading system,
with capacity for 34 risers and six mooring lines. It will
use a new vertical connection technique to tie in the flow
line bundle to the WCT