NEI-NO--828 NO9705280

ONS CONFERENCE 1996 27-30 AUGUST STAVANGER. NORWAY

Paper no. J 1

Session: DEEP WATER

Paper title: «The Campos Basin, Marlin and other deepwater fields»

Speaker: Antonio Carlos de Agostini ,

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PETROBRAS

ONS -96- OFFSHORE NORTHERN SEAS

AUGUST27-30 Stavanger, Norway

“THE CAMPOS BASIN, MARLIM and

OTHER DEEPWATER FIELDS”

Antonio Carlos S. de Agostini Member of the board, E & P Director PETROBRAS - Brazil J1

Abstract: The speech emphasizes the Brazilian deepwater production history driven with the usage of Floating Production Systems. As it flows from the first discoveries in the “shallow” part of the Campos Basin, through the Early Production Systems based on Floaters and the so called “120 meters deepwater” fixed production platforms in 1978, to the forecast of future discoveries in ultra-deep waters, highlighting the importance of offshore activity for PETROBRAS and Brazil. The development of the Marlim and other deepwater fields as well their features, using the Floating Production System, is presented. Discoveries already made in waters deeper than 2,000 meters are showed with potential prospective areas for exploration. The expected characteristics of these reservoirs and their fluids are also presented. The main accomplishments of the PETROBRAS PROCAP-2000 R&D Program are summarized. The technology trends, based on previous experience, as well as the future challenges to support the activities to be carried out in the ultra deep waters, are discussed. Key technology issues in deepwater exploitation scenario, such as horizontal and multilateral wells, high productivity wells, artificial lift in subsea wells, subsea equipment, flowlines and pipelines, produced fluid problems, floating production facility, subsea boosting and multiphase metering are also addressed. Finally, PETROBRAS ’ vision on what would the offshore production be like, when exploiting oil reservoirs of2,000 meter water depth, and beyond, is presented.

INTRODUCTION

Oil and gas activity in Brazil got started back in 1939. In nineteen 1968, the first offshore area was discovered. Peak production during this period was around 150,000 bpd. Production at this time was limited to onshore areas. Petrobras began its offshore production in 1973. It was in the Sergipe-Alagoas Basin. The water depth was around 30 m, quite a challenge for us at that time. Many other similar installations in the northern part of the country were then installed. We adopted the J1 existing solution that was to install a jacket and a deck with topside facilities. Jack-up drilling in cantilever or tender ship assisted drilling was applied. The process was very simple, and the production stream was sent to shore through 10 km long multiphase export lines. Campos Basin was discovered in 1974, through the Garoupa field and a new scenario was established. A new set of challenges were detected. The water depth was 120m, the distance to shore was more than 100 km and the production rate was around 7 times higher than in Brazil Northeast platforms. Campos Basin is currently the main petroleum province in Brazil. It is located offshore State, on the Southeast region of the country. Its area covers 100 sq. km. ranging from 50 into 3,400 meters water depth . The first production system installed in this basin began its production in 1977 (figure 1). Today, nineteen years later, the overall production system comprising 15 fixed platforms and 13 floating systems distributed among 33 oil fields which account for the production of 560,000 bpd ( which stand for 68 % of the domestic production ) and 10 million daily cubic meters of gas ( which represent 40 % of Brazilian gas production ). The accumulated production has far overcome the one billion barrels of oil milestone. This production is handled and exported to shore through over 2,800 km of oil and gas pipeline networks (figure 2). In 1974, for the exploitation of the first reservoirs in Campos Basin, in waters up to 120 m, Petrobras used International technology already available. Fixed platforms were used in waters between 120 and 200 meters, considered deep at the time. That was for sure a tremendous change in what we have done before and certainly it was the first step to a new era of production facilities. Parallel to this development Petrobras used, in full extent, the successful combination of Wet Christmas Trees and FPS, as Early Production Systems. In the year 1984, a new reference depth was brought to the Company, with the discovery of Albacora Field, followed shortly after by Marlim and Barracuda Fields. These three fields, extends from water depth of 250 to 2,000 meters. To face the new challenge, Petrobras conducted the first PROCAP, between 1986 and 1991. This was a six-year J1

R & D program with costs of over US 70 million, to develop technological capability to produce in waters as deep as 1,000 meters. Its success allowed the Company to recently bring into production such fields at low costs and high safety standards. Many research and development activities has been carried out in the world concerning deepwater technology. Petrobras has been playing an important role in this scenario throughout the past and present decades. It has recently brought into production its giant deepwater fields, Albacora, Marlim and Barracuda, with wells in waters as deep as 1,027 meters, or 3,370 feet.

THE IMPORTANCE OF DEEPWATER PRODUCTION TO BRAZIL

At the end of 1995, the total Brazilian reserves of oil and gas equivalent reached 11 billion barrels. 41% of that is located in deep waters, that is, between 400 and 1000 meters. The reserves located in depths over 1,000 meters, classified as ultra-deep waters, represent 22%. But in this case, it is first necessary to have technology to allow production in such condition. In short, Brazilian oil and gas equivalent total reserves in deep and ultra-deep waters stand for over 60% of the total (figure 3). The importance of deepwater technology can be also emphasized by the fact that according to Petrobras Exploration staff over 60 % of the potential oil and gas discoveries, that is, new fields where favorable characteristics indicate the existence of hydrocarbons, will be in deep and ultra deepwaters,. These figures reveal that Brazil’s future regarding oil production is strongly related to offshore fields located over 400 m water depths. Today, the Brazilian current oil production is 820,000 barrels per day. This production is not enough to meet the Brazilian market demand which is nowadays of 1,4 million bpd. Nine years from now, in the year 2005, the estimates indicate that PETROBRAS oil production will be able to reach 1.65 million bopd. This figure represents twice the current production (figure 4). J1

In order to increase Petrobras ’s domestic oil production, it must develop its deepwater fields. The estimate also indicates that around 70% of this oil production will come from deepwaters in 2005. From those figures expected for the near future, one can easily conclude that Petrobras is on the way to substantially increase its offshore activities by the end of the century. The amount of the reserves to be exploited during this period will be two times as big as the amount of the reserves already developed.

PETROBRAS EXPERIENCE WITH FLOATING PRODUCTION SYSTEMS

The table 1 showed below, demonstrates Petrobras experience on Floating Production Systems. We have more than 230 subsea trees already on the seabed, 2,500 kilometers of flexible lines and umbilicals laid, 38 Subsea manifolds and 14 FPS in operation. Significant increase is expected in the next 5 years, almost doubling the number of equipment installed. Equipment Installed Planned

96 - 2000

Subsea Trees 231 181

Subsea Manifolds 38 15

Subsea Flexible Flowlines (Km) 1,500 1,870

Control Bundles (Km) 1,000 980

Floating Production Units 14 12

Monobuoys 9 2

Table 1 - Equipment Demand Forecast

The installation of those 12 Production Systems and all the related equipment poses a significant challenge for a single oil Company. Satisfied with the performance achieved with the Floating Production Systems, particularly in deep water, Petrobras feels comfortable to install more 10 deepwater production systems to develop its oil fields, in the next 5 years, according to table 2.

FIELD EPS Type Process Storage Start of Water Number Plant Capacity Production Depth of Wells Capacity (bbl) (Bopd) Marlim P-19 SEMI1 100,000 Jun/97 770m 16 - Prod. Stawinner 12 - Ii^t 16 - PiST Marlim P-26 SEMI1 100,000 Oct/97 990m Iliad 08 - Injec Marlim P-33 FPSO2 50,000 2,000,000 Jan/98 730m 06 - Prod Henrique 3+1-Injec. Dias Marlim P-32 FSO 1 2,000,000 Apr/97 160m Cairn Marlim P-35 FPSO2 100,000 2,000,000 Mar/98 860m 18 - Prod. Jose 08 - Injec Bonifacio Marlim P-29 SEMI 130,000 Jun/99 940m 16-P^| or 12 - Injec. FPSO2

Marlim P-27 SEMI1 50,000 Apr/98 530m 07 - Prod. 03 - Injec. Albacora P-25 SEMI1 100,000 Oct/96 575m 10 - Prod Zapata (sat) Artie 16-Prod (2 man) Albacora P-31 FPSO1 100,000 2,000,000 Aug/97 330m 28 - Prod. Vidal de 07 - Injec. Negreiros Barracuda P-34 FPSO1 35,000 340,000 Jul/97 840m 11 - Prod PP Moraes TOTAL 765,000 8,340,000 (1) Under 485,000 4,340,000 Construction /Bid (2) Under 280,000 4,000,000 Design

APRIL/96

Table 2 - Floating Production Units Under Development

It is worth mentioning that those 10 systems will increase the Brazilian Production by 765,000 bpd, almost doubling the current output. The investments will be around US$ 4,5 billion for the production development.

Several factors make the subsea completion and Floating Production Systems as the natural choice for Petrobras to operate in deep waters. They are the following:

• Characteristics of the reservoirs and suitability to the location and environmental condition; • the reliability and cost-effectiveness showed by these systems; • its previous experience and the existence of trained staff to both specify and operate them, and ... • the possibility of a phased development, which has the well known benefits of minimizing the risks and capital exposure, while generating cash flow to support the next phases. J1

THE DEEP WATER FIELDS DEVELOPMENT The main projects going on at the moment are Marlim, Albacora and Barracuda & Caratinga field developments. These fields will be responsible for 46% of the Brazilian production in the year 2000.

THE MARLIM COMPLEX The Marlim Complex, see figure 5, was first hit on its main block on 1985. Later, in 1986, other strikes had been made at the adjacent areas named RJS-359 and RJS-382 in Dec/86 and Nov/87, respectively. In 1994, with some extension wells at these areas they were named Marlim East Block and Marlim South Block. The figure 6, shows the Marlim field development plan of its main block. The field went on stream on Mar/91 by the Pre-Pilot System, based on the semi-submersible P-13. On Aug/92 the Pilot system started operation and on June 94, the first Unit of the definitive system, the semi-submersible P-18, produced its first oil. At present, two semi- submersibles (P-19 and P-26) and three FPSO (P-32, P-33 and P-35) are under conversion. One Semi or FPSO which will be installed in the southern part of the main block is under a bid process. Some characteristics of the main block are shown below: Field area: 132 Km2 Reserves: 2,5 Bboe Water Depth: 600m - 1,050m Number of production wells: 86 Number of injection wells (directional/horizontal) : 42 Oil specific gravity: 19-21 API Oil peak production - Year: 530,000 bopd - 2000 Gas peak production - Year: 5.9 Mmm3/d - 2000

The Marlim South Block started to produce on May/94 through the well MRL-04, located in 1027m of water depth. This production supplies field data for the development of this J1

Other areas shown in the Marlim Complex are the RJS-377 and RJS-402 blocks, which will start production also by 1998 and the RJS-396 area, presently under evaluation. For the Marlim East Block, located in waters ranging from 1000 to 2000 m, the company is analyzing, during this year, the exploitation plans for this area.

THE ALBACORA COMPLEX

The figure 7 outlines the Albacora Complex, comprising its main block and the east block. The Albacora field has been in production since Oct/87 with a Pilot System based on a FPSO. The definitive system will count on two units: the P-25 (a converted semi- submersible) and P-31 (a converted FPSO), both presently under conversion. Figure 8 shows the field phase II development plan. Studies to anticipate the production of the Albacora East Block are being performed. The idea is to complete the well RJS-477, located at 1,100m water depth, equipped with a Submersible Centrifugal Pump (ESP). The target is to have the first oil by Mar/97. The collected data will guide the definitive exploitation plan for that area. Some characteristics of the Albacora main block are shown below: Field area: 111 Km2 Reserves: 663 MMbbl Number of production wells: 57 Number of injection wells: 6 Oil Specific Gravity: 27 API Oil peak production - year: 200,000 bopd - 1998 Gas peak production - year: 3.5 Mmm3/d - 1998

THE BARRACUDA & CARATINGA FIELD DEVELOPMENT The figure 9 shows the Barracuda & Caratinga field development plan for its Pilot System. The production unit will be a converted FPSO (P-34) moored in 835m of water depth. The first oil is expected by July/97. Preliminary evaluations for the definitive production system have already started. Collected data from the pilot system will guide the future J1

steps of the development. Production from the definitive phase is scheduled to start by beginning of 1999. Some characteristics of the Barracuda & Caratinga definitive production system are shown below: Field area: 153 Km2 Reserves: 1.1 Bbbl Number of production well: 71 Number of injection wells: 53 Oil Specific Gravity: 24 API Oil peak production - year: 200,000 bopd - 2003

THE DEEP WATER CHALLENGES

A series of challenges and constraints had to be faced and overcome in order to produce the deep water fields offshore Brazil. Although environmental conditions are milder, compared to the ones in North Sea or at the GOM, specific problems had to be solved before we could go on.

• Step-by-step development The first rule was to get data in advance to avoid, or at least minimize, the “surprises” during the field development. The use of pilot systems and the step-by-step development (modular) is highly recommended and is a default procedure at the company. By these means, future problems or adjustments in the development plans can be foreseen and its solutions can be provided for the next steps.

Some examples of the adoption of this strategy: (a) the detection of the possibility of organic deposits in the flow lines in most of the deep water fields and the development of solutions for the problem; (b) adjustment to the development plan of Marlim Field, without impairing the normal development plan, due to an increase in the production potential of the field; ( c) suppression of the water injection wells due to a better knowledge of the Albacora reservoir during the 1st module development. J1

• Ultra Deepwater Reservoir Characteristics

The ultra deepwater reservoirs with large extension area with small effective thickness, presenting low temperature often varying along the reservoir extension, and with relatively high oil viscosity poses a new set of challenges to the industry. These reservoirs characteristics may result in lower recovery factors than the desired . Since we are aware that these fields restrict the options for the application of conventional EOR (Enhanced Oil Recovery) methods, either from economic or technical point of view, they will require new approaches for the application of IOR techniques (Improved Oil Recovery).

• Extended Reach Wells

For deepwaters projects, the wells are responsible for more than 50% of both CAPEX and OPEX. In order to reduce that, the use of high productivity wells is a must. Non- conventional wells, such as Horizontal, Multi-lateral and Extended Reach Wells - the latter in order to increase the attractiveness of dry completions - will play an important role in this scenario.

• Low API Oils

The forecast for relatively heavy oil ( 15 degrees API ) production in ultra-deepwaters is another Petrobras concern. To assure the oil will flow through long distance subsea lines, under low temperature at sea floor, new subsea fluid-flow technologies will be required, as well as innovation in the existing artificial lifting methods.

• Subsea Equipment Innovation

A complete new set of techniques, equipment and procedures were required to develop the deepwater fields. Flowlines, which are mainly flexible had to be adapted to deeper waters. Thermal insulation among others enhancements, had to be added to the lines. Also light structures had to be used to reduce the loads of the risers in deep waters. The same happened to the Xmas-Trees, manifolds, and services equipment. J1

One of the main challenges is the need to develop or reengineer new subsea equipment required for the deepwaters. New Subsea Trees, flexible lines, lighter manifolds , reliable connection systems and boosting systems are required for the new environment.

• Hydrate And Organic Deposition

There are, in our deepwater projects, all conditions for organic deposits and hydrate formation in the flowlines where low temperatures, in both subsea floor and reservoirs, are predominant. That problem becomes a major concern as we move to ultra-deepwaters.

• New Mooring Systems

As the subsea lay-out in most fields is congested, mooring is also a major concern. A large mooring pattern, normally required for deep water mooring, can impose heavy costs to the subsea equipment if flow lines and risers have to go around them to reach their connection points. Also, it may impose the use of DP (Dynamic Positioning) vessels as they would be the only ones capable of operating in the nearby area.

New mooring technics must be developed so that the projects can optimize the subsea layouts and reduce the need of DP rigs for both development and maintenance phases, once they are scarce items in the market nowadays.

Costs are undoubtedly a major concern. The need of new technologies to allow production in deep waters must be linked with the need of keeping costs at competitive levels.

Of course, in order to overcome those barriers, we are aw are that in some cases we must pay the price of being pioneer mainly in prototype phase of a new development. We hope to share those efforts with other operators that are also willing to foster new deepwater technology by sharing both the benefits and also the costs of the prototype tests. PROCAP - 2000 - The home-made technological solution The ways to overcome the barriers found for deep water production were first addressed in the first PROCAP (Deep Water Capability Program) that aimed to generate the technology to enable the production up to 1000m, started back in 1986. In order to give continuity to the efforts of the first program toward 2,000m water depth, PROCAP - 2000 (Technological Innovation Program on Deepwater Exploitation Systems) was implemented in 1993 (see table 3). Those two programs together with many other internal projects, cooperation agreements, product and suppliers development had been carried out, extending the supply market and reducing costs.

So far, US$ 85 million have already been invested in both Programs and another US$ 37 million will be invested in 1996 and 1997 - mainly in prototype construction and installation.

A wide range of areas are covered by these development programs. These areas comprises from horizontal and highly deviated well technologies to subsea boosting systems.

Among the technologies required to produce in very deep waters, some of them, that are briefly described below, can be highlighted as the ones identified as major contributors in reducing costs or in improving performance or even in enabling the field development.

• SGN - Nitrogen Generation System Organic deposits will continue to be a major problem due to paraffinic compounds present in our oil, which precipitate at the low temperatures found in deep waters, blocking the lines and reducing flow rates.

Petrobras has developed a very effective termochemical method, called SGN, to mitigate this problem. More than 70 successful cleaning operations have been carried out in Campos Basin. It is important mentioning that this technology is available world-wide through a Petrobras licensee Company. J1

• ESP’s in Subsea Wells Artificial lift will certainly be required for subsea wells, specially for low pressure reservoirs. Gas lift will not be able to cover a broad range of applications for long step-out distances. Electrical submersible pumps in subsea wells, seem to be more suitable for this task, although downhole gas separators still need to be improved. The first subsea ESP prototype in the world is successfully running at the Petrobras Carapeba field in 90 m water depth, since October, 1994, that is, 22 months of flawless smooth operation. Six partners were involved in this pioneer work, and this cooperation was a key factor for the success.

• Steel Catenary Riser

Petrobras is planning to install at the end of this year, the first Steel Catenary Riser (SCR) on a Semi-Submersible, which we consider as a strategic step for the oil industry. Once the practical feasibility of the SCR is proven, it will provide a cost-effective option to export or import hydrocarbons, either to or from Floating Production Units. It will be an alternative to the expensive flexible pipes and based on that, it is possible to foresee a direct and indirect cost reduction. The main reason to perform a full-scale comprehensive monitoring of a SCR prototype is to better understand the real behavior of such an innovative device. Data gathered will make it possible to confirm the analytical modelling and, therefore, calibrate the design parameters.

The SCR technology has not accumulated a large industry experience yet. In order to evolve SCR technology a little faster, through its application on a moored Floating Unit, Petrobras is developing this project.

• Taut Leg Mooring The Taut Leg Mooring System will replace conventional mooring system for the majority of the future floating systems to be installed. J1

Its main advantages are: sharp reduction on the mooring radius, as can be seen for the Marlim field case, increased payload, and lower offset . In addition, the use of the taut leg concept is considered very important for the development of the deepwater fields, since it reduces the needs for DP rigs, and allows the Optimization of the subsea layout.

» Boosting Systems The attractiveness of subsea boosting has been confirmed in our recent screening study for the three giant deepwater fields, conducted by the Company. The main idea is to install these boosters close to the wellheads to transport the produced fluids to a Floating Production System.

Petrobras has set up a test site at Atalaia and is investing in three different types of technology, ESP's in Subsea Wells, Multiphase Pumping and Subsea Separation. We joint the VASPS project and we are carrying on the Petroboost, the Petrobras patent gas driven system.

Now, in its fourth year of ongoing work , the deepwater research program, PROCAP 2000, has reached the prototype phase, mainly for the projects related to the boosting systems.

We are confident that these new technologies can add value to the deepwater developments by cutting down costs perbarrel produced in up to 30%.

• ESP's in Subsea Wells (RJS-477) As a testimony of our confidence, it is important to notice that the next step of the Subsea ESP Project will be the installation of a pump in the well RJS- 477, located in 1,100 meters water depth, in East Albacora field. It will use a guidelineless horizontal tree, special 9 km electrical cable, and a subsea transformer . J1

The Future of Ultra - Deepwater Production - Petrobras Vision

At the end of this paper , I would like to share our vision of an “ultra” deepwater production system, where there will be a few high productivity subsea horizontal wells, connected to subsea manifolds, and then to subsea boosting systems. The wells may be equipped with an ESP. From the boosters the production will be sent to a FPSO, located in 1000-1500 meters water depth range, through flexible or steel pipes. The produced oil will be transferred to a shuttle tanker connected in tandem, while the gas phase is compressed either to reinjection or to be sent to shore via steel pipeline.

Conclusions All the deepwater exploration and production experience acquired by Petrobras over almost twenty years, together with the existence of an effective integrated Brazilian scientific and industrial basis, as well as an aggressive R&D Program, are ready to be used by the industry. We are working hard to push back the limit of technology so that we can bring the new projects to reality. As I mentioned earlier, the true challenge in deepwater is using technology to make the development sound economical but, if adequate planning and risk management is used, even with the present available technologies they can be successfully faced. A phased (step by step) development strategy, where risks and capital exposure are minimized, is an interesting approach that also allows cash flow to finance the next phases. This has been the PETROBRAS approach over the last years, and we believe that it can be successfully applied worldwide.

ACKNOWLEDGMENTS

The author wish to thank the colleagues from the E&P Department and R&D Center for their contributions, support and cooperation. Special thanks are due to Marcos Assayag, and Orlando Ribeiro for a careful review of the paper. J1

BIBLIOGRAPH

1. Assayag , M. I. et al; Petrobras Technological Development Program on Deep Water Production Systems - PROCAP , 1991, 7th International Symposium on Offshore Engineering, Rio de Janeiro, Brazil.

2. Ribeiro O. J. S.; Deepwater Brazil: A Challenging Subsea Market, 1994, 8th Underwater Technology Conference, Bergen, Norway.

3. Assayag, M.I. et al ; Petrobras Technological Innovation Program on Deepwater Exploitation Systems - PROCAP-2000, 1995, World Energy Council 16th Congress, Tokyo, Japan.

4. Camargo, R.M.T. et al.: Innovative Subsea Boosting Technologies On Deep Water Scenarios - Impacts And Demands , February 1996, Worldwide Deep Water Technologies, London, UK. 5. Bonesio, P.A ; Deepwater Developments Offshore Brazil, February 1996, Worldwide Deep Water Technologies, IBC, London, UK. 6. Ribeiro O. J. S. et al; The Impact of Subsea Boosting on Deepwater Field Development, May 1996, Offshore Technology Conference, Houston, TX, USA J

PROCAP - 2000 PORTFOLIO

NUMBER SYSTEMIC PROJECT STABILITY IN HORIZONTAL AND HIGHLY 1 DEVIATED WELLS DRILLING HIGH - ANGLE WELLS IN 2 UNCONSOLIDATED AND UNSTABLE SHALES KICK AND BLOWOUT CONTROL IN 3 DEEP WATER WELLS ELECTRICAL SUBMERSIBLE PUMPS IN 4 SUBSEA WELLS (ESPS) 5 SUBSEA SEPARATION SYSTEMS (SSS) SUBSEA MULTIPHASE PUMPING 6 ‘ SYSTEMS :r i etUFS lk . FLOW ASSURANCE IN DEEP WATER 7 CONDITIONS VARIABLE FREQUENCY ELECTRICAL 8 ENERGY TRANSMISSION SYSTEM STATIONARY PRODUCTION UNITS 9 WITH DRY COMPLETION 10 DEEPWATERFPSO/FSO

ACQUISITION AND TREATMENT OF 11 GEOLOGICAL, GEOPHYSICAL, GEOTECHNICAL AND OCEANOGRAPHIC DATA DEEPWATER SUBSEA PIPELINES 12 ( GATHERING, SALES AND CONTROL) Table 3 Campos CAMPOS BASIN 1977

FIGURE 1

Campos CAMPOS BASIN

AUJACORA Lagoa Feia

EAST MAHL'M

SOUTH MARliM

FIGURE 2

ARQUIVO: 801.COR OIL PRODUCTION POTENTIAL FORECAST

550

1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 figure 4 J 1

BRAZILIAN TOTAL RESERVES 11 .Ox 10’ bbl

OFFSHORE TOOOm > WO > 400m

V OFFSHORE OFFSHORE WD < 400m WO > 1000m : ONSHORE %

. - , , - um PmOMAi "V"' - „ , .

FIGURES

EAST MARLIM

FIGURE 5

ARQUIVO: B02.CDR :j(1) 150 000 bopdf 130.000 bopd

100.000 bopd

100.000 bopd

KC>»:W,^.p68W»eW:tWk,f:-.

FIGURE 6

EAST

FIGURE 7

ARQUIVO: B03.CDR j r

ALBACORA - PHASE II

lws«wrrF«ae> otawnwrowwOTproi

FPSO

»p

FIGURE 8

GAS PIPELINE TO PNA-T

T RJS-383

RPSIORAES

C'ARATIN^V

FIGURE 9 ARQUIVO: B04.CDR