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Abstract Flow Assurance started to be a concern in PETROBRAS in the mid 80´s, with the development of the Albacora Field, which was the first field produced at a water depth below 400 meters in Campos Basin. Since that time, PETROBRAS relies heavily on technological research and development to provide solutions that can grant the safe, continuous and optimized operation of its subsea fields. This paper reviews the efforts regarding Flow Assurance Management in Campos Basin, under a historical point of view, following the new challenges that were posed as water depths became deeper and deeper, and the techniques and practices developed to face them. Also are reported here the current R&D efforts under the PROCAP-3000 program, aiming to address Flow Assurance Management in water depths up to 3,000 meters (9,840 ft). Introduction Since Flow Assurance started to be a concern in PETROBRAS in the mid 80´s, with the development of the Albacora field, large investments have been made in R&D, through the PROCAP program, aiming to make viable the production and pipeline transportation of oil in this harsh environment, at water depths below 400 meters in Campos Basin. This scenario is where the occurrence of waxes, hydrates, asphaltenes and scale become a critical issue.

The first challenge faced in the beginning of the production of the Albacora Field was to keep the continuous operation of the pilot production system, which was not originally designed to handle the large degree of wax deposition that was taking place in the production lines. The first solution was to change the production line, which was very expensive and did not really solve the problem. This challenge was overcome with the in-house development of the thermo-chemical method known as SGNTM –Nitrogen Generation System. The lessons learned with this pilot system were the driven forces of the development of methods to predict and prevent wax deposition, which will be discussed in

this paper. These methods incorporated a new way to design the production system, and were eventually used with success in the development projects of subsequent fields in Campos Basin, such as Marlim and Roncador.

When the development of Marlim took place, in the early 90´s, already reaching water depths of 1,000 meters (3,280 ft) and below, cases of hydrate formation started to appear, initially in the completion phase. With the increase of the BSW in the production phase, hydrate formation in production lines and subsea equipment also became a problem. Taking a similar strategy to the one used for dealing with wax deposition in Albacora, PETROBRAS invested in the research and development of methods to predict, prevent and control hydrate formation in the production of deep offshore fields.

Nowadays in PETROBRAS, and particularly in Campos Basin, Flow Assurance is still a problem and a challenge for this production scenario. But the learning process and the investment made in R&D turned the Flow Assurance Management a well-developed and successful issue, which extends its scope beyond the waxes and hydrates formation phenomena, dealing also with strategies to control scaling, emulsions, asphaltenes and severe slugging as well. The First Ten Years (1977-1987) In the first ten years of Campos Basin, production the fields were located predominantly in shallow waters (up to 300 meters – 984 ft). In this period, the problems of flow assurance were limited to wax occurrence in the flowlines of some wells at Badejo field, scale deposition at Namorado field and some hydrate blockages in gas pipelines. Badejo oil came from a basaltic formation and it had high wax content as compared to other oils from Campos Basin. At that time, periodic cleanings of the flowlines with aromatic solvents were needed to keep optimal flow conditions. At Namorado field, the mixture of formation water containing relatively high amounts of barium and strontium with sulphate rich injection seawater resulted in a highly saturated system of barium and strontium sulphates, causing precipitation and scaling of these compounds onto the base of the production tubing (1). To reduce the production losses and the high costs of workover for replacing clogged tubings, a successful scale prevention policy was adopted, through a scale inhibitor squeeze treatment. Beginning of the Deepwater Exploitation According to the exploitation philosophy of the Campos Basin, fields located in deepwaters were developed in stages, always starting from a pilot system, namely Early Production System. This Early Production System had the objective of

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Management of Flow Assurance Constraints Carlos Bandeira Cardoso, Iberê Nascentes Alves, Geraldo Spinelli Ribeiro, PETROBRAS

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collecting information about the reservoirs and produced fluids, in order to subsidize the final exploitation plan to the field, as well as to provide revenue anticipation. These pilot systems ordinarily conjugated the use of floating production units equipped with a compact process plant and of subsea wells linked by flexible flowlines.

Albacora Early Production System. The Albacora Field, discovered in September 1984 through the wildcat well RJS-297, is located in the northern part of Campos Basin in water depths varying from 230 to 950 m (755 to 3,120 ft). Because its great dimensions and the required investments, its development was designed at that time to be accomplished in three phases. The first phase consisted of a Pilot System that started to operate in October 1987. That system, shown in Fig.1, was designed and built with fourteen producer wells, two subsea manifolds and the P.P. Moraes FPSO, a Floating Production Storage and Offloading unit located at 205 m (670 ft) water depth. The wellheads were as far away from the subsea manifolds (5,000 m –16,000 ft) as the manifolds were from the FPSO (4,000 m –13,000 ft).

After a year of operation, that system began to show what would be its biggest fragility: severe wax deposition in the flowlines, process plant and oil storage tanks. The system design was totally inappropriate to control this phenomenon because it didn't count on pigging and chemical inhibition facilities, heating of the storage tanks or other resources. In spite of the wax content of the Albacora oil to be not that high (a characteristic in fact common to the oils from Campos Basin) when compared to oils from other Brazilian basins, the deposition was outrageous mainly because of the low flow temperature that it was submitted to. In order to remove the wax from the lines, it was initially tried the use of aromatic solvents that were shown to be ineffective due to the low ambient temperature. Due to this unexpected problem the production losses of the field were significant, and five clogged flowlines had to be replaced until April 1992 when the first successful SGNTM offshore operation was accomplished in the test production flowline of subsea manifold (2, 3). Thanks to this thermo-chemical method of wax removal, it was possible to avoid new wax clogging and thus Albacora became the top oil production field in the country by the end of that same year.

In an effort to keep reducing the rate of wax deposition of the pilot system, other two initiatives were also considered: the injection of a wax chemical inhibitor into a well flowline (RJS-329) through a X-mas tree hydraulic control line and the manufacture of a pig-Xover, a subsea piggable loop device installed at the flowline hub of the X-mas tree of a new well (AB-13) that would be directly connected to the FPSO. Such device allowed a round-trip of a 4 in solid cast pig from the gas-lift to the production flowline. The test with the wax chemical inhibitor was interrupted after a period of 16 months due to an unfavorable cost-benefit relationship, but it proved to be technically viable(4). It was necessary, however, to look for a cheaper product. On the other hand, regarding the round-trip pigging, the benefit was shown to be more attractive. It was proven the viability of the concept and its effectiveness in the wax buildup control. The use of both procedures as

remediation techniques became to be considered in the subsequent production systems designs.

The pilot system operated with P.P. Moraes FPSO up to 1993 when the ship was replaced by the P-24 FPU, a Floating Production Unit based on a semi-submersible, but the original subsea layout had stayed in operation up to 1999.

Marlim Pilot System. The Marlim Field was discovered in January 1985 through the wildcat well RJS-219A and it extends over water depths from 650 m to 2,600 m (2,130 ft – 8,530 ft). The pilot system, whose production began in July 1992, counted with a FPU based on a semi-submersible platform (P-20) anchored at 620 m (2,034 ft) in which were connected ten subsea oil production flowlines from wells with offsets that varied from 1,700 to 5,600 m (5,600 to 18,400 ft). As happened in Albacora, the design of Marlim pilot system also didn’t considered facilities for the wax control. However, in this case there were less production losses due to the occurrence of a smaller wax deposition rate in the flowlines, related to the Marlim oil characteristic, allied with the recent availability of SGNTM process. Besides that, three years later some design modifications were accomplished in the platform that allowed the use of low density (28 kg/m3) foam pigs for running in the flowlines. Although this kind of pig has a limited scraping power as compared to polyurethane solid cast pigs, it had a surprisingly performance in Marlim, where the wax deposit has a friable consistence and, therefore it is easier to remove compared with the one of Albacora. Another advantage of the low density foam pigs was their ability to be run into circuits without special designs for pigging operations. For instance, the pig was run through a very irregular loop, comprising a 6 in diameter production flowline, 4 in production riser, 2.5 in gas-lift line, small ratio curves and accentuated restrictions, such as the X-mas tree crossover valve with a bore of 1.9 in. Bijupirá/Salema Pilot System. The adjacent Bijupirá and Salema fields were discovered in 1990 through the wells RJS-412 and RJS-373A. The field extension covers water depths varying from 480 m to 880 m (1,570 to 2,890 ft). The pilot system that began operation in August 1993 consisted of three subsea wells (two from Bijupirá and one from Salema) connected to the P-13 FPU, a semi-submersible platform anchored at 630 m (2,070 ft). The lengths of the flowlines varied from 3,200 to 8,100 m (10,500 to 26,580 ft). The stabilized oil was transferred through an 8 in diameter and 21 km (13 mi) long pipeline to a tanker ship connected to a mono-buoy. The system, not appropriately designed for the wax control, faced at the beginning of operation significant production losses. The Bijupirá wells had severe wax deposition problems in the flowlines and in the pipeline. In both pipes the wax was not removed in an effective way by the foam pig, fact that demanded frequent SGNTM treatments.

In 1996, was implemented with success a new application of SGNTM, named SGN “on-line”, that comprised of injecting the heat generating chemicals directly into the flow stream without interrupting it (5). Thanks to this technique there was a significant decrease of production losses in the Bijupirá Salema pilot system, which operated until April 2000.

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The Development of the Deepwater Giant Fields The largest problem faced in the operation of the pilots (Early Production Systems) in deepwater was, without any doubt, the intense wax deposition problems, due to oil flowing under low temperatures conditions. The development of the new deepwater fields by means of subsea equipment and floating production units was strongly dependent on the flow assurance control design. It was of vital importance deepen the studies (that had being accomplished in the first phase of PROCAP Program since 1986) related with the prediction, prevention and mitigation of wax buildup.

The secondary recovery method selected and used in Campos Basin deepwater fields was water injection. This method is very effective for that scenario, but there is a side effect: the water production increases after the breakthrough and brings other concerns related with Flow Assurance, namely the possibilities of hydrate and scaling formation in the oil production lines.

The occurrence of severe slugging caused mainly by the flowline-riser geometry and configuration is another concern for this scenario due to the large diameter and long distances lines.

Flow Assurance Project. In face of these new challenges, PETROBRAS decided to create in 1992 the Flow Assurance Project under auspices of PROCAP-2000 Program, which main objective was the development of drilling and production technologies for oil and gas exploitation in deep and ultra-deepwaters (1,000-2,000 m). The Flow Assurance Project, today in its third phase, component of PROCAP-3000 portfolio, during eleven years has contributed decisively to the improvement of the deepwater exploitation systems design. In the first Flow Assurance Project (1992-1996), the main focus was to investigate technologies to mitigate wax problems in order to assist the scenarios of the Marlim and Albacora fields. At that time those fields were in phase of design of the permanent exploitation systems. The project opened several work fronts aiming to contributed to these designs, such as pipeline thermo-hydraulic calculation tools, lab methods to determine the Wax Appearance Temperature (WAT), pigging, SGNTM process, wax chemical inhibitors, pipeline heating/insulation and magnetic tools. Besides that, were also incorporated to the project studies that already had being carried on hydrate formation and on phenomena associated with instabilities in the multiphase flow.

Albacora Permanent Production System. The Albacora permanent production system, as shown in Fig.2, counts today with two FPU, the P-25 semi-submersible platform and the P-31 FPSO, fifty seven wells and six subsea diverless manifolds. From a pilot system in which some wells were threatened of shutting down in face of serious wax buildup problems, the situation was changed to a system where the production losses related to wax are insignificant and arise from gas-lift discontinuity during the round-trip pigging. To contribute to this fact a judicious exploitation design in which the aspects concerning to flow assurance were prioritized, especially:

• accomplishment of a proper subsea layout design in which in most of the cases the temperature of the multiphase flow was above WAT during the field lifetime;

• installation of facilities that allowed the running of a solid cast pig in some wells where a higher wax deposition rate was expected;

• installation of piggable subsea manifolds. Marlim Permanent Production System. Due to the size and the complexity of the project, the development of this giant field was planned in five modules consisting of seven floating production units (four semi-submersible platforms and three FPSOs) and one Floating Storage and Offloading tanker (FSO) as shown in Fig.3. The oil production gathering from around eighty wells to the FPUs is made through flexible lines and four subsea manifolds.

The permanent development system of the field began in May 1994 with the installation of the P-18 FPU. The Marlim oil is processed in its units and transferred to tanker ships that transport all the production to shore. All the produced associated gas is compressed on the FPUs and exported to the continent through the gas pipeline network installed in Campos Basin.

As happened in Albacora, the Marlim development project also got benefits of the acquired experience at pilot phase and of the technologies developed and made available by the Flow Assurance Project. A proper subsea layout minimizing, whenever possible, the wells offset and the installation of topside and subsea facilities that could run pigs were always assumed as design premises. Nowadays these actions proved to be the right ones: in the period when the field reached production peak (around 600,000 bopd), no production losses were associated with wax deposition.

Moving Toward Ultra-Deepwater The development of the giants fields of Marlim Sul and Roncador (Figs. 4 and 5), located in water depths up to 2400 m (7,900 ft), demanded the release in October 1997 of the second phase of Flow Assurance Project. The objectives of this new phase were mainly to ensure the feasibility of these two enterprises (6).

The hydrate control in multiphase flow and the development of techniques to locate and to remove wax and hydrate plugs into subsea lines stood out among the new objectives, since the initial modules of the new fields would count on horizontal or extended reach wells with long tiebacks to central processing floating units (Fig. 6).

In face of this scenario, design and operation guidelines, which resulted from acquired experience along almost two decades of exploitation in deepwater, have been used to manage flow assurance constraints. The highlights of these guidelines are next presented.

Wax. Due to the complexity of the mechanisms involved in wax deposition, the forecast of this phenomenon is based on several analyses. Some of them are related to thermodynamics of wax precipitation. Another concern is to quantify the amount of wax deposits that can be formed from specific crude. For the first case, for instance, the thermo-hydraulics

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profiles referring to the steady-state flow are compared with the WAT, obtained through differential scanning calorimetry. To determine the wax deposition potential a cold-finger test is performed and the result is compared with reference values obtained for crudes from fields whose wax deposition history is already known.

The following options are currently adopted to define the techniques used for prevention, mitigation and removal of wax: • thermal insulation of the subsea flowlines and risers of the

production wells designed to keep the steady state flow temperature 3 ºC above WAT over the field lifetime. It is interesting to mention that the early applications of insulated lines in Roncador field led to measurements of arrival temperatures at the production unit below than those predicted by the simulators. Investigative tests performed showed that thermal conductivities of flexible lines and risers in a high pressure environment are higher than those claimed by the supplier, this fact was then considered in further flow simulations;

• installation of topside and subsea facilities for running pigs in all well flowlines and oil pipelines must be perfomed. Depending on the tendency for wax deposition of each oil, it should be used low or medium density foam pigs or polyurethane solid cast pigs;

• to grant a proper device for chemical inhibitors injection into flowlines the installation of a 0.5 in diameter line connected at X-mas tree is a design recommendation for all the wells;

• installation of topside facilities to allow the access to the riser and flowline with a coiled tubing from the FPU in order to aid in the removal of blockages by injecting solvent fluids can also be considered in future projects.

Hydrates. Regarding hydrates prevention, PETROBRAS makes use of different strategies, according to the product transported in each line.

For lines where predominantly gas flow takes place, gas dehydration, through glycol regeneration units, is the procedure used for hydrates prevention. As an operational contingency, projects always contemplate the possibility of using ethanol as an inhibitor for the water phase.

For subsea production lines, the prediction of the potential to hydrates formation is made through the analysis of the hydrates dissociation curves obtained at an in-house developed software, compared with the transient (for well start-ups, shutdowns and restart operations) and permanent flow thermo-hydraulic profiles. In this case, prevention strategy considers the individual or combined use of the following procedures: • thermal insulation of lines: the heat exchange coefficients

of the flowlines and riser should be prescribed such that the values for the permanent flow thermo-hydraulics profiles must be out of the hydrates formation envelope during all operational times along the field’s lifetime. For transients happening in shutdowns and restarts, allowed cool down times are in average between 2 to 8 hours, depending on the fluids’ tendency to hydrate blockage formation. This tendency is established from the fluids’ characterization based on some lab analyses such as gas

composition, SARA (Saturated, Aromatic, Resin and Asphaltene) analyses and rheology tests on transition from water in oil emulsion to hydrate suspension. In general, the oils from Campos Basin do not present hydrate blockage tendency. In fact, the contrary has been observed in almost all fields: the oil phase acts as natural inhibitor of hydrates agglomeration, hindering in this way line blockage. This may be attributed to the presence of natural surfactants (resins and asphaltenes) in its composition, that also favors the formation of a highly stable water in oil emulsion;

• topside depressurization: topside facilities must available in such a way that a complete depressurization of production lines can be achieved within 2 hours from the shutdown;

• removal of fluids from production lines: in those shutdown cases that extents longer than cool down times, the replacement of the fluids by Diesel (or other suitable fluid) before restarting production should be considered.

Typical Hydrate Occurrences. In permanent flow conditions, hydrates blockages observed in Campos Basin have occurred only in gas lift lines or gas export lines. This usually happens because of isolated cases of malfunctions in the gas dehydration plants or in alcohol injection. In these cases, bilateral depressurization (or, when unavoidable, unilateral depressurization) procedures are adopted. In subsea oil production lines, no blockages were reported so far during permanent flow operational conditions, even in the case of a well with 80% water cut, flowing with a subcooling of 5 ºC. Specifically in this case, hydrates may have been formed, but the oil surfactant characteristic hindered the agglomeration of the hydrates pellets into a complete block.

On the other hand, some obstructions were reported in flowlines, during well start-ups, shut-in and restart operations. The main prevention procedure adopted to avoid these occurrences consists in the previous replace of the fluids existing in these lines by Diesel oil, eventually using pigs and batches of ethanol.

The removal of blockages in flowlines can be harder to do in the cases where liquids are present in the riser, exerting a hydrostatic pressure on the hydrate plug. In such cases, commonly a workover rig is needed to unplug the line and it may last for several days. However there were cases in which was possible to perform the hydrate removal using a coiled tubing from the FPU to inject Nitrogen and remove the liquid from the riser (7).

Asphaltenes. Although asphaltenes deposits have not been verified in Campos Basin, prediction analyses are always performed. Based on empirical observations, PETROBRAS has adopted the concentration of n-heptane needed for initiating asphaltene flocculation (measured in ml/g of crude), as the best correlating parameter to predict the precipitation potential. If the value is above 2 ml/g, the crude is considered stable and asphaltene problems should not be expected due to pressure and temperature changes in the production processes.

The asphaltene onset is determined by two methods. The first is the spectrophotometer method, in which the absorbance of the n-heptane/crude mixture is measured, and the second is

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the optical method, in which the onset is determined through visual observations using optical microscope (8).

Scale. PETROBRAS has dealt with various commercially available thermodynamic models to predict the scaling potential in new fields. The choice among these codes depends on the conditions of scale formation. OKSCALE has been applied to predict scale formation under high pressure, temperature and ionic strength conditions; for low temperature simulation the GWB and MULTISCALE are used.

So far, the main deepwater fields are in the development phase, and the level of produced water is still low for those in operation. Therefore, problems associated with scale have not been observed in most of the wells. Nevertheless, production losses have been recently detected in some wells from these fields and bullhead removal treatments have already been successfully applied in them from the production platform through the gas lift line, avoiding the high costs of a rig workover (9). Although the present production systems have no dessulfation plants, this is an option being considered in new systems design and it will be used for the first time on P-52 platform in Roncador field, aiming to prevent barium and strontium sulfates.

Severe slugging. PETROBRAS has not faced major severe slug problems in Campos Basin. Some isolated problems were reported in shallow waters fields(10), and were usually related to a specific facilities design problem. The solution of these problems normally took only small modifications in topside layouts.

However, there is awareness that this may constitute a major problem, mostly in the case of flows of water in oil emulsions in systems where a high GOR is present. Failures in determining correctly the rheological properties that govern the multiphase flow may lead to over sizing production lines and consequently to severe slugging situations.

For the prediction of such transients, PETROBRAS counts on commercial and in-house software. Some considerable work has been taken also on the better understanding of the emulsion flow characteristics, on the measurement of rheological properties and on the interpretation of their impact on flow. PETROBRAS has also some patented techniques to eliminate severe slugging which were already tested successfully in laboratory situations (11, 12).

New Challenges The objectives PROCAP-3000 call for making viable the production of fields in water depth up to 3000 meters. In the already discovered fields in Campos Basin, PROCAP-3000 focus technology for application in the next phases of development at the Marlim Sul and Roncador fields, as well as the Marlim Leste and Albacora Leste fields projects. PROCAP-3000 portfolio includes R&D projects in Flow Assurance comprehending the following efforts:

Multisize pig development. The cost of having piggable flowlines is significant, especially for satellite wells where the diameter of production lines outsizes the diameter of gas lift lines. Although the foam pigs proved to be effective for removing certain types of wax deposits, a more efficient

multisize pig is desirable. This project aims the development, manufacturing (in partnership with a vendor) and testing of a new design prototype of multisize pig.

Pipeline and flowline plug location and removal methods. This project aims to develop techniques and equipment for locating and removing blockages caused by wax and hydrates in flexible lines, production risers, transfer pipelines and subsea manifolds. It will also propose a contingency plan for the main scenarios of subsea lines in deepwaters, making available equipment and software for location of blockages and special procedures for removing them.

Prediction of wax deposition. Advanced laboratory and theoretical methods for predicting wax deposition rates in multiphase pipelines are still needed for performing proper technical and economical analyses. This project calls for the evaluation and improvement of current laboratory characterization and predictive tools by correlating their results with real field experiences.

Hydrates in subsea multiphase production system – phase II. Deepwater and ultra-deepwater fields usually will produce oil with considerable amounts of water at a certain point of their lifetime, because of the secondary recovery through sea water injection. This scenario favors the hydrate formation, with the consequent risk of blocking lines and subsea equipment. On the other hand, it is known that the heavy and polar oils from Campos Basin have a tendency to inhibit hydrate agglomeration. This project aims at studying hydrate formation in oil dominated systems, improving knowledge of the crystallization kinetics in emulsions and the impact of pressure drop in the flow, as well as the influence of hydrate formation in the wax crystallization and vice-versa.

Comparison of piggable, insulated and electrically heated lines alternatives for ultra-deepwater systems. This project aims to compare different flowline and riser alternatives to be used in association with currently available artificial lift methods for a typical ultra-deepwater field in Campos Basin. This is to take advantage of the hint that current subsea layout and artificial lift methods can be improved by taking a system-integrated approach.

Pipe-in-pipe flowlines and risers. This project aims at making this technology available for application in a PETROBRAS typical ultra-deepwater scenario. It proposes to work on the design, fabrication and installation methods and equipment. Depending on the results of the comparison studies mentioned before, these developments may lead to the test of prototypes.

Electrically heated flowline and riser. Its goal is similar to the previously mentioned project and it will be especially attractive for avoiding the risk of hydrate blockages in flowlines during well shut-in and start-up conditions. Conclusions Regarding Flow Assurance, the deepwater production in Campos Basin required along the past 20 years an integrated

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work of different specialists from the research, development, design and operational areas. This was essential for the continued improvement of the production systems design.

PETROBRAS has been investing in obtaining and improving predictive models for the occurrence of waxes, hydrates and scaling. For this, a previous, detailed and integrated characterization of the fluids of a newly discovered field has been of vital importance to subsidize the design of its future exploitation system.

The pioneer work of deepwater oil exploitation had, among its major challenges, to overcome the significant production losses associated mainly to wax deposition in subsea production lines. Initially, the efforts in obtaining and improving techniques for remediation of this problem, the most successful among them being the SGNTM and the use of pigs, were responsible for the survival of some pilot systems. Then, focus was deviated to preventive actions, such as the design of subsea layouts with shorter and, when possible, thermal insulated flowlines, so to guarantee a permanent flow temperature above the WAT throughout the productive lifetime of the field.

In the giant deepwater and ultra-deepwater fields a significant amount of produced water (because of the secondary recovery through sea water injection) is expected in their later production lifetime. This scenario favors both the formation of hydrates and of sulphates scale. This has moved a lot of PETROBRAS efforts to invest in new techniques for prevention of these phenomena as, for instance, the electrical heating in subsea lines for the case of hydrate control. Regarding prevention and mitigation of sulphate scale, both the implementation of dessulphation plants in future projects and the (already tested and well succeeded) restoration of productivity of subsea wells through remote (from the FPU) bullheads dissolver treatments are being considered as possible solutions.

This review of the Flow Assurance issues during the 25 year operation of Campos Basin can only conclude that the great efforts on research and development achieved results that were of capital importance for allowing production in such harsh environment. Acknowledgments The authors would like to thank PETROBRAS for the permission to publish this paper. References 1. Bezerra, M.C.M., Rosário, F. F., Khalil, C.N.: “Scale Control in

the Namorado Field, Campos Basin, Brazil,” IBC Conference Solving Oilfield Scale Problems, Aberdeen, 20-21 Nov. 1995.

2. Khalil, C. N., Neumann, L.F., Santos, I.G., Menezes, C.A.L., “Thermochemical Process to Remove Paraffin Deposits in Subsea Production Lines, OTC 7575, Offshore Technology Conference, Houston, May 2-5, 1994

3. Neumann, L. F., “Otimização Operacional do SGN – Relatório Final”, Projeto Garantia de Escoamento 2, Internal Report, Petrobras, 2001

4. Vieira, L. C., “Avaliação de Desempenho de Produto Inibidor de Parafina no Poço 3-RJS-329A do Campo de Albacora”, CT SETRAF 21/94, Internal Report, Petrobras, 1994

5. Khalil, C. N., “SGN Technology – Controlling Deposits Buildup in the Petroleum Industry”, IIR Conference - Waxes, Hydrates & Asphaltenes, Aberdeen, 17-18 June 1998.

6. Minami, K., Kurban, A. P. A., Khalil, C. N. and Kuchpil C., “Ensuring Flow and Production in Deepwater Environments”, OTC 11035, Offshore Technology Conference in Houston, Texas, 3-6 May 1999

7. Freitas, A.M., Lobão, A.C., Cardoso, C.A.B., “Hydrate Blockages in Flowlines and Subsea Equipment in Campos Basin”, OTC 14257, Offshore Technology Conference in Houston, Texas, 6-9 May 2002

8. Minami, K., Cardoso, C.A.B.R., Bezerra, M.C.M., Melo, A.P., “Roncador Field Development – The Impact of Fluid Properties”, OTC 12138, Offshore Technology Conference in Houston, Texas, 1-4 May 2000

9. Bezerra, M.C.M., Rosário, F. F., Rocha, A.A., “Scale Prediction and Remediation for Deep Water Fields,” SPE 80403, International Symposium on Oilfield Scale, Aberdeen, 29-30 Jan 2003

10. Barbuto, F.A.A. and Caetano, E.F., “On the Occurrence of Severe Slugging Phenomenon in Pargo-1 Platform, Campos Basin, Offshore Brazil”, Proceedings of the 5th International Conference on Multiphase Production, Elsevier Science Publishers Ltd, 1991.

11. Barbuto, F.A.A., “Method of Eliminating Severe Slug in Multi-Phase Flow Subsea Lines, Application for UK Patent, #2 282 399, 1995.

12. Almeida, A.R., Gonçalves, M.A.L., “Device and Method for Eliminating Severe Slugging in Multiphase Stream Flow Lines”, Application for UK Patent, #9820277.3, 1998.

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Fig. 1 – Albacora Early Production System

Fig. 2 – Albacora Permanent Production System

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Fig. 3 – Marlim Permanent Production System

Fig. 4 – Marlim Sul Module-1 Production System

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Fig. 5 – Roncador Development Modules

Fig. 6 – Roncador Module-1A Typical Subsea Layout

FPU P-52Mod. 1A (2005)

FPU Mod. 2 (2006)

FPSO Brasil Mod. 1A (2002)

FPU Mod. 2 (2007)

MODULE 1A -Phase 2

Oil Export 18”

Gas Export 10”

Umbilicals

Steel CatenaryRiser

SS at 1800 m WD

Production Well

ANMHGas Lift Manifol

d

Insulated Flexible J

Insulated Flexible J

Average Distance = 6,8 km

PLET Vertical

Connexion

Insulated Rigid Line

InsulatedRigid Line