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Copyright 2003, Offshore Technology Conference

This paper was prepared for presentation at the 2003 Offshore Technology Conference held inHouston, Texas, U.S.A., 5–8 May 2003.

This paper was selected for presentation by an OTC Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, aspresented, have not been reviewed by the Offshore Technology Conference and are subject tocorrection by the author(s). The material, as presented, does not necessarily reflect anyposition of the Offshore Technology Conference or its officers. Electronic reproduction,distribution, or storage of any part of this paper for commercial purposes without the writtenconsent of the Offshore Technology Conference is prohibited. Permission to reproduce in printis restricted to an abstract of not more than 300 words; illustrations may not be copied. The

abstract must contain conspicuous acknowledgment of where and by whom the paper waspresented.

AbstractSignificant volumes of heavy and high viscosity oil have beendiscovered in the Campos and Santos Basins, offshore Brazil,and its economical production is a challenge for theoil industry.

New production technologies are required for theeconomic development of offshore heavy oil reservoirs. Longhorizontal or multilateral wells, produced with high power ESPs, hydraulic pumps or submarine multiphase pumps, could

partially compensate the decrease in productivity caused bythe high oil viscosity. The flow assurance could be improvedwith insulated or heated flowlines or, alternatively, with theuse of water as the continuous phase. The heavy oil processingin a Floating Production Unit is not straightforward, and newseparation technologies, as well as the feasibility of the heavyoil transportation with emulsified water, should beinvestigated. The existence of light oil reserves in neighboringreservoirs, even in small volumes, would be an important issuefor the commercial feasibility of the heavy oil area.

The Petrobras experience with offshore heavy oil fields inthe Campos Basin shows that some can be economically

produced. However, the economic feasibility is controlled byfactors such as: reservoir characteristics; water depth;

possibility of blend with light oil; oil acidity and

contaminants; price scenario; fiscal regime; availability of new production technologies; transportation, refining andmarketability of the heavy oil.

The recently created Petrobras Heavy Oil TechnologicalProgram – PROPES – is in charge of the development,together with universities, service companies and the industry,of new technologies for the offshore heavy oil fields. Themain objective of all this work is to set the basis for theeconomical development of the significant volumes of heavyoil already discovered offshore Brazil.

This paper presents the main research and developmentopics of the Petrobras Heavy Oil Program, as well as the key

production technologies for the target fields. Additionally, theresults of some well tests and Extended Well Tests (EWT) inheavy oil reservoirs in the Campos Basin are presentedand discussed.

Introduction

In the Campos and Santos Basins, heavy oil is beinggenerically defined as any oil that is heavier or more viscousthan the Marlim Field oil. The Marlim Field (ref. 1), located inthe Campos Basin under water depths from 650 m to 1,100 min operation since 1991, currently produces around 98,000m3/d (620,000 bpd) of a 19o to 22o API crude. The Marlim liveoil viscosity is between 4 and 8 cP and the dead oil viscosity is

between 400 and 500 cP at 20o C.The industry reference for offshore heavy oil production is

the Captain Field, located in shallow water in the North Seaoperated by ChevronTexaco (refs. 2-5). The Captain oiviscosity at reservoir conditions is about 90 cP (refs. 2-5)much higher than the Marlim oil viscosity. However, at

surface conditions, the viscosities of both oils are quitesimilar. As some of the offshore heavy oils recently foundoffshore Brazil are more viscous than the Marlim and Captaincrudes, at surface conditions, the production process will bemuch more challenging.

In 1991, when Petrobras started production in the MarlimField, through two wells at 700 m of water depth connected toa semi-submersible platform, the development of this giantdeepwater field was a challenge. The intensive development ofnew production technologies, led by the Petrobras PROCAP(Deepwater Technologies Program), made it possible toovercome the technical difficulties. In some aspects, Petrobrasis now facing a similar challenge: to produce offshore heavy

oil field, most of them in deepwater.

Difficulties for heavy oil production in the Camposand Santos BasinsMost of the heavy oil reservoirs discovered in the Campos andSantos Basins are located in water depths above 1,500 m. Thereservoirs are shallow, in many cases, which results in lowreservoir temperatures, between 40 and 60o C. The rock isusually unconsolidated sandstone, with high permeabilitywhich may compensate the high oil viscosity, in terms owell productivities.

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Offshore Heavy Oil in Campos Basin: The Petrobras ExperienceA.C. Capeleiro Pinto, C.C. M. Branco; J.S. de Matos; P.M. Vieira, S. da Silva Guedes ; C. Pedroso Jr.; A.C. DecnopCoelho; M.M. Ceciliano, Petrobras S. A.



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Many difficulties are envisioned for producing these heavyoil accumulations, and some of them are discussed below.

In the appraisal phase, one of the most importantobjectives is to obtain a reliable oil sample, which enables thecomplete oil characterization, including the viscositydetermination and the water-in-oil emulsion characterization.

A complete well test, in a cased well completed with sandcontrol, is usually required to guarantee that the sample isreliable, particularly in non-consolidated sandstone reservoirs.

Long horizontal length wells are necessary to achieve high productivities and improve the waterflood sweep efficiency.Drilling and completing this kind of well in shallow reservoirsin deepwater are not easy tasks. The low fracture gradients inthe deepwater reservoirs in the Campos Basins – usuallyaround 0.60 psi/ft – complicate the gravel pack operations dueto the risk of fracturing the well at the casing shoe.

The artificial lift of the heavy oil is critical, since the highviscosity crude, containing emulsified water, causes highfriction losses in pipes. The heat management is another important issue, regarding the paraffin, asphaltene and hydratedeposition risks.

Regarding the recovery mechanism, it is known that thecold heavy oil production process is not efficient for offshorefields. Natural depletion, even with natural pressure supportmechanisms, such as high rock compressibility and strongaquifer, will result in low recovery factors. The water injectionmethod, applied in almost all the giant fields in the CamposBasin, is also not efficient, due to the unfavorable mobilityratio between the water and oil phases.

Despite of the recovery method, large amounts of water will be produced with the heavy oil. The application of existing technologies for oil-water separation in theProduction Unit would require very high temperatures and

large retention times, which may be unfeasible. Regarding thegas-oil separation, special attention should be given to thefoaming tendency of the heavy oil, which affects the

processing plant design.Oil storage, offloading and transportation will also require

concern regarding to the heat management, particularly for high pour point oils.

Heavy crudes in some cases present high naphtenic acidity,which may reduce its market value. Besides, the potential for the deposition of naphtenates (a kind of organic-metallicscale) should not be neglected.

Finally, it is worth mentioning that, for offshore heavy oilfields, the Value of Information of an Extended Well Tests

(EWT) is, in general, very high. The EWT allows anticipatingmost of the production problems – formation damagemechanisms, artificial lift performance, processing plant

performance, oil storage, offloading and transportation.However, the logistics to perform an EWT, in deepwater, may

be very complex.

Testing Offshore Heavy Oil WellsPlanning. When planning an offshore heavy oil well test it isimportant, at first, to keep clear the objectives of the test.Sensitivity studies, using a reservoir simulation model, andconsidering the uncertainty range for each parameter, help

identifying the parameters which most affect the productionforecast and the economic results, for instance:

• Live oil viscosity.• Horizontal and vertical permeabilities.• Well productivity.• Tarmat barrier close to the OWC.• Oil-water relative permeabilities.• Rock compressibility.• Aquifer support.However, some of the parameters above can not be

obtained through a conventional well test.As mentioned, special attention should be given to the oi

sampling and determination of the live oil viscosity, since itcontrols not only the displacement efficiency in the porousmedia but also the flow up to the platform. The openholesampling may be non-reliable, even if all the gas is collecteddue to the contamination with mud filtrate and sand, difficulto be completely eliminated in the laboratory. The correctfluid characterization usually requires a cased hole well tesand a single-phase bottomhole sampling. Recombination

samples may also be non-reliable, due to the difficulties tomeasure the low GOR during the test, not to mention the riskof loosing intermediate fractions of the oil.

As most of the turbiditic sandstones in the Campos andSantos Basins are non-consolidated, the well test, to beconclusive, requires the installation of a sand contromechanism. As the heavy oil wells usually do not naturallyflow to the surface, efficient downhole artificial lift devicessuch as a progressive cavity pump (PCP) or an electricasubmersible pump (ESP) should be provided.

In some cases it is necessary to evaluate the necessity ofdrilling a horizontal well in the appraisal phase, to guaranteethat a minimum productivity will be reached, allowing the

objectives of the well test to be achieved. The decision tree presented in Figure 1 helps defining the appraisal strategy oan offshore heavy oil discovery, including the necessity of ahorizontal well, a conventional well test and an Extended WelTest (refs. 6, 7). The decision must be taken considering theValue of Information approach (refs. 8, 9).

Having in mind the objectives of the well test, a carefusequence of events is defined, considering possible failuresand contingency procedures. It is important that this job ismade by a multi-disciplinary team, with a full-timecoordinator. The well-test on paper is exercised in periodicmeetings, involving not only the internal team but also theservice companies.Hurdles. The key points to be considered in an offshoreheavy oil well test are related to:

• Formation damage due to fluid loss and the difficultiefor the well clean-out.

• The efficient oil-water separation at the rig.• Downhole installation of the ESP, including the cable

penetration through the BOP and tie to the test stringappropriate slips to handle the test string and surfaceequipment to protect the electrical cable and subseatest tree hydraulic hose at rotary table.

• Casing drawing and well design to attempt themaximum dog leg specified for the ESP and the tes



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string, taking into account the necessary drift for theESP cable and protectors or inox bands.

• Rig selection: it must have excellent stability, reliableDP system, wide deck, power generation capability for the ESP, BOP ram compatible to the necessary BOPCAN and diverter model that do not damage theESP cable.

Special concern should be given to the security procedures,considering the possibility of a quick disconnection during thewell test. The separation process of the heavy oil, containingemulsified filtrate requires a long planning, consideringcontingence procedures.Petrobras experience. For more than 10 years Petrobras has

been performing well tests in offshore heavy oil wells, and the procedures have been gradually improved. In the past the testswere performed with the help of nitrogen circulation and,when using pumps, they were positioned above the BOP.

Currently, almost all the offshore heavy oil well tests inPetrobras are performed with the pumping equipment installeddownhole. In some cases diesel is pumped through coiled

tubing, to help the well clean out.An impressive offshore heavy oil well test was recently performed by Petrobras, with a dynamically-positioneddrilling ship in a well located under a water depth of 2,000 m,in a non-consolidated reservoir containing an extra viscous oilwith very low gas content. Since it was suspected that the oilviscosity could be high, to guarantee that a sufficient

productivity would be obtained, a horizontal well with 1,000m of horizontal length in the reservoir, was drilled andcompleted with an openhole gravel pack. A tubing mountedESP was installed downhole and the well could flow the extraviscous oil with rates up to 700 bpd. The test was a completesuccess, allowing a reliable monophasic bottomhole sampling,and the determination of the reservoirs parameters and the

well productivity. Figure 2 shows an overview of the surfaceequipment used in the well test. Figure 3 shows details of theRiser Sealing Mandrel used to protect the electrical cable andhydraulic hose at rotary table. Figure 4 shows the BOP CAN,which allows closing the BOP RAM withouth damaging theESP cable. The surge tanks (with electric heating) used in thesecond stage of separation, with flow rate measurement as a

back up, are shown in Figure 5.

Extended Well Tests in Offshore Heavy OilReservoirs in PetrobrasExtended well tests (EWTs) in offshore fields are the best wayto reduce the uncertainties and mitigate the risks before

approving the huge investments associated to the definitive production system. Petrobras has a long tradition in operatingEarly Production Systems (EPS) or perform EWTs in itsdeepwater fields – Marlim, Marlim Sul, Marlim Leste,Roncador, Barracuda, Caratinga, among others. From thereservoir engineering standpoint, the early production allowsnot only to prove reserves through material balance, butmainly to gain knowledge about the reservoir internalcharacterization, which is critical for the success of waterflooding projects.

For offshore heavy oil fields, however, the main objectiveof an EWT is to figure out the whole production process. The

use of the Value of Information (VOI) methodology (refs. 89) is fundamental to allow the approval of an EWT or an EPSin offshore heavy oil fields, since they may not pay outconsidering just the EWT cash flow. The VOI can justify theEWT, considering the optimization it would provide for thedefinitive system (see Figure 1).

A good example of an EWT in offshore heavy oil was the

one performed in the Captain Field in 1993 (ref. 10), which sethe basis for the economic development of the fielddiscovered sixteen years before. Many issues related to the

production process were investigated, such as: vertic permeability, oil-water relative permeabilities, water coning behavior, performance of the long horizontal length welartificial lift system and processing plant.

In the next topics we describe two Extended Well Tests performed by Petrobras in offshore heavy oil areas.

EWT in the Marlim Sul Field. The Marlim Sul Field islocated directly south of Marlim Field, comprising an area ofmore than 600 km2, under water depths ranging from 1,000 to2,600 m. The field was discovered in 1987 by an exploratorywell drilled in 1,250 of water depth which found 40 m of theOligocene / Miocene age reservoir saturated with 25o API oilThe oil quality reaches 28o API at the northern part of the fieldand decreases as water depth increases. As for the neighboringMarlim Field, the reservoir rock properties are excellentHowever, the stratigraphy is more complex, which makes the

prediction and identification of the reservoir compartmentimportant but difficult tasks. To investigate the reservoir

performance and anticipate production problems, thrExtended Well Tests were implemented in the field. In thistopic we will discuss the one that dealt with heavy andviscous oil.

In August, 1997, the subsea completion world-record at

the time, well MLS-3B, drilled in the water depth of 1,709 m,was connected to a Floating Production Storage andOffloading (FPSO), moored in 1,300 m of water depththrough 3 km of subsea flowline (Figure 6).

The vertical well perforation was 40 m in length and thewell was gravel-packed. The well resulted damaged, but, as itwas not essential for the EWT, no attempts were made toremove it. MLS-3B produced a 16.5o API oil, with 3,000 cP a20o C, during one year, being shut in August 1998. In the

beginning, the well produced through natural flow, havinreached almost 1,000 m3/d (6,300 bpd). After one month, thegas lift was started and the well rate jumped to 1,500 m3/d(9,500 bpd). Later, it was necessary to restrict the well rate

due to the increase in the well GOR. During the production process, the oil temperature at the FPSO varied form 15o C to10o C. The wax appearance temperature was around 17o C, buno paraffin deposition or other flow assurance problems werereported, even after shutdowns. Important informationregarding the low temperature flow in the subsea pipeline andriser, as well as the gas-lift performance, were gathered andallowed the calibration of the multiphase flow correlations.

At last, it is worth to mention that new subsea technologydeveloped by the Petrobras PROCAP were successfully testedduring the EWT of MLS-3B, particularly the FPSO mooringsystem and the 6” riser performance, allowing the



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optimization of the production installations for fields locatedin deeper waters.

The results of the EWT were extremely useful for thereview of the development concept of deep water portions of the Marlim Sul field.

EWT in Jubarte Field. Jubarte is the most recent oil field

discovered by Petrobras in Campos Basin, what took place inJanuary 2001. The field is located about 70 km offshore theEspírito Santo State, under a water depth of 1,300 m. Themain reservoir is a non-consolidated Cretaceous turbidite,containing a 17o API oil.

The discovery wellwas tested without sand contentionmechanism and presented a productivity index insufficient toguarantee commercial rates in the deepwater environment.

A study based on the Value of Information supported thedecision of drilling a horizontal appraisal well. In February2002, it was drilled, preceded by a pilot well. The horizontallength was 1,070 m, completed with an openhole gravel pack.The final result was amazing, with a well productivity index13 times higher than the vertical well PI. An EWT was

proposed and approved, with the VOI approach, with theobjectives of:

• Investigate the aquifer strength and its connectionwith the oil zone.

• Allow material balance calculations.• Calibrate the Kv / Kh ratio, fundamental to optimize

the development plan.• Calibrate the oil-water relative permeability with

production data.• Impose a drawdown in the reservoir to allow the

identification of compartments, if they exist, reducingthe risks of the development plan.

•

Identify damage mechanisms in the long horizontalwell during the production process.• Investigate the natural flow and artificial lift

performances.• Anticipate problems related to the production

facilities, regarding to gas-oil and oil-water separation.• Evaluate the performance and reliability of the storage

and offloading procedures currently used.• Improve the processing and marketing strategies for

the heavy oil.The Seillean FPSO, a dynamic positioning vessel with the

capability of performing light workover operations, which wasoperating in the neighboring Roncador Field, was mobilized to

allow the heavy oil production in a water depth of 1,300 m.Some improvements in the processing plant were necessary inorder to process the heavy and viscous oil of Jubarte.

Using an innovative solution, a 900 HP, 25,000 bpdcapacity ESP was installed above the X-Mas Tree (Figure 7).The well was connected to the FPSO through a 6” riser.

The production started in October 2002 and the well produced by natural flow during two months, with a stabilizedrate of 16,500 bpd, with constant bottomhole pressure. InDecember 2002 the ESP was turned on and the flow rate wasincreased to 18,300 bpd, being limited due to the constraints inthe processing plant at the FPSO. The well potential with the

ESP is 23,000 bpd but some changes are necessary in the processing plant and surface pumping system to alloincreasing the flow rate. The major problem detected in theseparation process is related the severe foam formation, whichis being mitigated with the use of chemicals.

The Jubarte oil is similar to the MLS-3B oil at surfaceconditions, that is: the dead oil viscosity is 5 times the Marlim

dead oil viscosity. It is one of the most viscous oils, at surfaceconditions, being produced offshore through a subseacompletion well. During the EWT two extension wells weredrilled and the field was declared commercial. The excellentresults of the EWT are currently being used to optimize thedevelopment plan for the Jubarte field.

Critical Technologies for the Development of Offshore Heavy Oil Fields

New technologies are required to allow economdevelopment projects for offshore heavy oil.

Starting with the reservoir aspects, the displacement of oil by water should be improved. Simulations show that ImprovedOil Recovery (IOR) techniques, such as polymer flood, cansignificantly increase the recovery factor. This technologyhowever, depends upon the availability of polymers resistanto high salinity water, since the mixing should be made withsea water. Furthermore, the logistical limitations in theoffshore environment should not be disregarded.

Another important issue is related to the oicharacterization. Better openhole sampling techniques, forviscous oils in unconsolidated reservoirs, are required, in ordeto decrease the exploratory costs. Better prediction of the oivariation with depth and along the reservoir, considering thegravitational segregation (as detected in many Campos Basinreservoirs), the temperature variation and the oil genesis

process itself, could guide the drilling of the appraisal well

and improve the field value estimative. At last, but not leastthe prediction of the existence and characterization of thesealing potential of the tarmat bed, sometimes present at the

bottom of the heavy oil zone, close to the oil water contact, isextremely important. A limited connectivity of the bottomaquifer with the oil zone would avoid the rapid water coninggrowth, allowing a more efficient water injection pattern andradically changing the development scheme.

The oil-water relative permeabilities control thewaterflooding displacement process in heavy oil reservoirsMany issues still deserve developments in this area, such astransient versus steady state measurement methods; influenceof the displacement velocity; residual oil saturation

determination, among others. To be representative, thedisplacement tests should be performed in the nonconsolidated plugs, containing live oil and restored wettabilitywhich, definitely, is not a simple procedure. The PetrobrasResearch Center (CENPES) is developing techniques toimprove these measurements, including the use ofX-ray tomography.

Well tests, as discussed, are complex for offshore heavyoil, particularly in deepwater. Many operational details stilldeserve technology development, but the discussion of theseissues is beyond the scope of this paper.



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The optimization of the well pattern is crucial for theeconomic development of a heavy oil field. In Petrobras, thequality map technique (ref. 11) is being successfully applied,although the technique is not yet fully automated. It is clear that the key factor to improve the recovery in heavy oilreservoirs produced with water injection is to increase the welllengths effectively exposed to the reservoir. Simulations show

that, for viscous oils, the reservoir behaves as if each welldrains a single reservoir block and, consequently, if portionsof the horizontal length do not contribute to flow, theassociated oil will not be produced. Figure 8 shows a crosssection along the horizontal path of a well in a viscous oilreservoir with a bottom aquifer (in red). Some well grid blockswere kept shut in, to simulate damaged intervals. It can beobserved that the oil located below the damaged intervals isnot produced. The existence of non-contributing intervalscould be checked through production logging with the well inflow, which, however, does not work well for viscous oils,leading to the necessity of the development of new productionlogging devices or methods.

Reduced well spacing is necessary when waterfloodinghigh permeability heavy oil reservoirs. Figures 9 and 10 showcross sections in a reservoir with a bottom aquifer (in blue),developed with horizontal wells, comparing the water injection efficiency for an injector-producer spacing of 900 m(Fig. 9) and 450 m (Fig. 10). It can be seen that the closer thespacing the higher the recovery: in this case the recoveryfactor jumped from 10.1% to 21.7% with the inclusion of thesecond producer.

Therefore, the main challenges in the well technology areaare related to drilling and completing long horizontal lengthsin non-consolidated reservoirs. The deepwater heavy oilreservoirs in the Campos and Santos Basins usually presentlow fracture gradients, which complicates the gravel packing

operations in long horizontal lengths. Despite the difficulties,Petrobras has an excellent experience with openhole gravel

packing (OHGP) in horizontal wells and keeps advancing inthis area. In spite of the good experience with OHGP,Petrobras has installed expandable sand screens (ESS) in somehorizontal and high-angle wells, and this technique may be analternative for the completion of long horizontal lengths.

Another important issue in the well technology area is thecapability of isolating swept out intervals in long horizontalsections. Currently, External Casing Packers (ECP) are beingused to allow the isolation in OHGP wells, but only the toecan be easily isolated. If other intervals are to be isolated, theoperation will require more complicated techniques, since a

tubing is not run into the horizontal section and there are nosliding sleeves to control the production. In the future, withthe improvement of the reliability of intelligent completionsystems, the workover operations will not require expensiverig interventions.

Finally, it is worth mentioning that, as the main driver for cold heavy oil production is the effective well length, there isalso a good scenario for multilateral wells.

Artificial lift and flow assurance are other critical issuesfor exploiting offshore heavy oils. Reliable artificial liftdevices, specified for high rate – high power and long MeanTime to Failure (MTTF), must be available during the

development phase. When dealing with Dry Completion Units(DCUs) or other Production Units with a dedicated rig (e.g.FPDU), the use of Electrical Submersible Pumps (ESP) seemsto be a good option, since a rig will be available for deployingthe pump. ESP deployment in satellite wells requiresexpensive interventions, which is a motivation for enhancingthe reliability of the pumping systems. Petrobras has a good

experience with ESP in subsea wells in deepwater (ref. 12) but there is room for technology developments, regarding thereliability. In the Captain Field, the platform wells producewith ESPs, but the satellite wells are equipped with HydraulicSubmersible Pumps (HSP), powered with water (refs. 3-5).

In the beginning of the year 2004 a subsea multiphase pumping system will probably be installed by Petrobras in theflowline of a satellite well in the Marlim Field. The success othis equipment may provide another option for the heavy oifields development, with the important benefit of avoiding theexpensive rig interventions for the equipment retrievalAnyway, as more than 80% of the Campos Basin wells

produce with gas-lift, the use of ESPs, HSPs, Jet Pumps oother artificial lift methods represents a completecultural change.

Regarding to the flow assurance issues, efforts areconcentrated to understand the water-in-oil emulsion behaviorand modeling, so that the prediction and also the design of the

pipelines can be optimized. The core-flow process using wateris being developed by Petrobras under a research contract withthe University of Campinas (UNICAMP) and may be anoption to improve the heavy oil flow. In fact some core flowtests performed in an onshore heavy oil field wereencouraging. Inverted emulsion flow presents the sameadvantages, with the drawback of requiring larger quantities owater. Heat management is other critical issue, mainly if theheavy oil presents a high pour point. Besides an efficient hea

management system, techniques like heated water circulationelectrical flowline heating and pipe-in-pipe insulation may

be necessary.Oil-water separation, as well as the oil treatment to meet

the refinery requirements, is perhaps the most critical item forthe whole offshore heavy oil development. The use of thecurrent technology would result in very high separationtemperatures, which can be unfeasible. Petrobras is planningsome tests with standard technology in a fixed platform in theCampos Basin, which processes a blend of light oil reservoirswith a 13.7o API oil reservoir. The idea is to deviate the heavyoil to a dedicated separation train and test the separationefficiency, comparing with the theoretical simulations, and

various chemical products. It is estimated that, for the 13.7API oil, temperatures between 120o C and 150o C would berequired for the gravitational separation and even higher forthe eletrostatic separation. It can be concluded that compacequipments, designed with new technologies, not yet tested ina field scale, are required for such conditions.

The best option would be to separate the produced water athe sea bottom (mudline) and reinject it in the reservoirHowever, due to the high density and viscosity of the oil, anefficient and complete subsea separation seems to be quitecomplex. If the technological gaps are met, the heavy oisubsea separation system will also require reliable control and



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monitoring systems. The produced water reinjection,containing oil particles, will require high pressures to achievethe target injection rates. If fractures are created in thereservoir during the reinjection process, special attentionshould be given to monitoring its propagation.

An alternative to be investigated is to simplify the offshoreseparation, removing just the free water and exporting the oil

with the emulsified water. The full separation could be doneclose to the terminal, onshore.The gas-oil separation for heavy oils also deserves

attention, due to the severe foaming tendency. Petrobras iscurrently testing chemical products to reduce the foam that islimiting the potential of an offshore heavy oil well.

Once the oil is brought to the surface and separated fromgas and water, the problems are not finished. Storage,offloading and transportation of the oil will require an efficientheat management process, requiring special equipments.

Finally, new technologies to reduce the naphtenic acidityof the oil are required, since it is not unusual that the heavycrude present high Total Acid Numbers. Several technologiesfor the oil acidity reduction are being developed by Petrobras,under the Refine Technology Program (PROTER). Newrefining routes to improve the value of the heavy oil arefundamental to allow the economic feasibility of the heavyoil fields.

Innumerable parameters affect the decision of developingoffshore heavy oil, but we may say that the main driver istechnology development. The technology developmentrequires not only investment and expensive field tests, buttime. Without new technologies, which require time for development and maturation, and field tests in pilot scale, thecommercial disclosure of offshore heavy oil fields may bevery difficult.

The good news regarding the offshore heavy oil in Brazil

are related to the significant volumes discovered in world-class reservoirs in the Campos and Santos Basins, which couldcompensate the efforts in developing the new

production technologies.

The Petrobras Offshore Heavy Oil TechnologicalProgram (PROPES)In October, 2002, Petrobras launched a TechnologicalProgram with focus on its Offshore Heavy Oil Fields. TheProgram, named PROPES, covers most of the upstreamdisciplines and also an interface with the downstream area.The objective is to develop or integrate existing technologiesthat may turn into reality the challenge of producing the heavy

oil already discovered in the Campos and Santos Basins.In fact, the significant heavy oil volumes recentlydiscovered are in the 13 – 17 API range, with oil viscosities

between 20 and 400 cP at the reservoir conditions. Some of the heavy oil fields are located in shallow waters, whichsimplify the appraisal and development strategies, but most of them are in deep water, which brings extra complexity.

PROPES is divided in 9 systemic projects:• Reservoir engineering techniques for offshore

heavy oil.• Long horizontal length wells.

• Equipments for large bore horizontal wells.• Artificial lift of heavy and viscous oil.• Flow assurance and transport of heavy and viscous oil• Separation and treatment of heavy and viscous crudes.• Integrated evaluation and production mobile system.• Production units suitable for heavy crudes.• Characterization and pre-treatment of heavy crudes.

Each systemic project comprises several R&D projects andcurrently a total of 34 R&D projects are ongoing.

The program is multi-disciplinary, and its close interactionwith other Technological Programs in Petrobras, likePROCAP (Deepwater Technologies Program), PRAVAP(Advanced Oil Recovery Program) and PROTER (RefineTechnologies Program), helps covering any possible gap.

Among the main R&D projects we can depict:• Development and application of high-power, high

rate, large MTTF Electrical Submersible Pumps. The project comprises the investigation of the ES performance with free gas fractions up to 40% pumping oils with viscosities up to 400 cP.

• Feasibility analysis of alternative artificial lift methodfor heavy oil in deepwater, such as jet pumpshydraulic submersible pumps, progressive cavity

pumps, among others.• Characterization of water in oil emulsions, in order to

improve the accuracy of pressure and temperature profile prediction in production strings, flowlineand pipelines.

• Drilling and completion with sand control mechanismof long horizontal well lengths in non-consolidatedsandstone reservoirs, with low fracture gradients. Thecasing diameter must allow the installation odownhole artificial lift systems.

• New technologies for oil-water separation. The systemshould be compact enough to be installed on a floating production unit and present a good performance withreasonable separation temperature and residence time.

• Production units to deal with heavy oil and, mainlywith large quantities of produced water, which could

be reinjected. Aspects of reservoir managemenincluding well side-track and workovers, are

being considered.The technology development is being made on a step-by-

step basis, and, whenever possible, will be tested in shallowwater or onshore fields before being extended to the deep-water environment. The completion date of the Program i

scheduled to 2007.

ConclusionsPetrobras experience with heavy oil fields in the Campos andSantos Basins shows that some of these fields could beeconomically produced, under special conditions. Theeconomic feasibility is controlled by factors such as: reservoircharacteristics; water depth; possibility of blend with light oiloil acidity; contaminants in the oil; transport, refiningcapability and marketability of the heavy oil, and, mainly, bythe price scenario. As emphasized along the paper, thedevelopment of new production technologies – long



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horizontals, reliable high rate artificial lift devices, efficientheat management, compact oil-water separation systems,among others – is fundamental to optimize the heavy oil

projects and make them economically feasible. The fiscalregime and the deadline for the appraisal of the offshore heavyoil discoveries are other important variables to be consideredwhen analyzing the economics of these projects.

The heavy oil well test operations in deepwater arecomplex and expensive, requiring special techniques toachieve the test objectives, including the reliableoil characterization.

Extended Well Tests are necessary to reduce the risks of the definitive system in offshore heavy oil fields, what can bequantified by the Value of Information methodology. SomeEWTs have been successfully performed by Petrobras inheavy oil fields in the Campos and Santos Basins. However,some of the reservoirs that have been discovered offshoreBrazil present oils that are heavier and more viscous thanthose which have already produced in the EWTs.

The successful history of Petrobras in developing deepwater technology encourages the company to the challenge of

producing offshore heavy oil. The recently created OffshoreHeavy Oil Program, PROPES, intends to coordinate thedevelopment or integrate existing technologies that may turninto reality the challenge of producing the significant heavy oilvolumes already discovered in the Campos and Santos Basins.

AcknowledgmentsThe authors would like to thank Petrobras for the permissionto publish this paper, and to the professionals in the PetrobrasE&P Production Engineering Group and in the ResearchCenter (CENPES). A remarkable contribution was given bythe professionals from the Business Units of Macaé (UN-BC),Rio de Janeiro (UN-RIO), Espírito Santo (UN-ES), and the

Services Unit (E&P-SERV), responsible for the fieldoperations described in the paper. We also thank Dr. ÁlvaroMarcello Marco Peres for reviewing the paper.

References1. Pinto, A. C. C., Guedes, S. Bruhn, C. H. L., Gomes, J. A

T., Sá, A. N. and Fagundes Netto, J. R. : “Marlim ComplexDevelopment: a Reservoir Engineering Overview”, SPE69438, (2000).

2. Jayasequera, A. J. and Goodyear, S. G.: “The Developmenof Heavy Oil Fields in the UK Continental Shelf: PastPresent and Future”, SPE 54623, (1999).

3. Etebar S.: “Captain Field Development Project Overview”OTC 8507 (OTC, 1997).

4. Lach, J. R.: “Captain Field Reservoir DevelopmenPlanning and Horizontal Well Performance”, OTC 8508(OTC, 1997).

5. Etebar, S.: “Captain Innovative Development Approach”SPE 30369, (1995).

6. Del Lucchese, C., Pinto, A. C. C. , Decnop, A. C. andBranco, C. C. M.: “Extended Well Tests in Offshore OiFields”, Petrobras Internal Seminar, (2001).

7. Pinto, A. C. C., Trindade, W.L. and Matos, J. S..: “OffshoreHeavy Oil: A New Challenge for Petrobras”, III E-ExitepVera Cruz, Mexico, (2003).

8. Demirmen, F. – “Use of Value of Information Concept inJustification and Ranking of Subsurface Appraisal”, SPE

36631, (1996).9. Demirmen, F. – “Subsurface Appraisal: The Road from

Reservoir Uncertainty to Better Economics”SPE 68603, (2001).

10. Pallant M., Cohen D. J. and Lach, J. R.: “ReservoiEngineering Aspects of the Captain Extended Well TesAppraisal Program”, SPE 30437 (1995).

11. Cruz, P.S., Horne, R.N. and Deutsch, C. V.: “The QualityMap: a Tool for Reservoir Uncertainty Quantification andDecision Making”, SPE 56578, presented at the 1999ATCE, Houston, Tx, 3-6, (1999).

12. Mendonça, J. E., Mattos, C. H. S., Ritterhaussen, J. H.“The First Deepwater Installation of a Subsea ESP: RJS477, Campos Basin, Brazil”, OTC 10969, presented at theOTC, (1999).



8 OTC15283

N

Saia

Y

Y

Y N

Y

N

N

Careful plan the EWT

FPSO contracting, X-Mas TreeObjectives :

Artificial lift performance,Flow assurance analysis,

emulsion effects, separationand oil treatment

Does VOI payout the

EWT?

Calculate VOI for anExtended Well Test

Feasibility

Drill horizontal

1

Does VOIpay out ?

Development feasible with this

well design?

Developmentfeasible with

horizontalwells?

Estimate VOI todrill and test ahorizontal well

Careful well testdesign: Sand Control, artificial lift, Monophasic sampling,

Gas-oil separation

Offshore heavy oil discovery

Y

1

N

Out

1

Y

N NDoes VOI payout casing and

well test ?

HorizontalSide-track?

Other well ?1

Figure 1 – Decision tree for an

offshore heavy oil well test



OTC15283 9

Figure 2 – Overview of the surface arrangement for a deepwater heavy oil well test

Fig 3 - Riser Sealing Mandrel to protect the electrical cable and hydraulic hose at rotary table

Riser sealing mandrel

Flow Head

Sheave for the electric cable

Spread bars and long slingsfor coiled tubing ; the

contingency to guaranteethe flow was to pump diesel

through coiled tubing

Surgency line :Coflexip

Deep Water Frontier : RIG FLOOR

Electrical cable for ESP

SSTT hydraulic hose



10 OTC15283

Fig 4 – BOP CAN : to allow closing the BOP RAM withouth damaging the ESP cable.

Figure 5 –Surge tanks (electric heating) as a second stage of separation / flow rate measurement as a back up

6 5/8” bop can



OTC15283 11

Figure 6– FPSO offloading during the EWT in Marlim Sul.

Figure 7 – Jubarte Extended Well Test scheme

F P S O - S E I LL E A NF P S O - S E IL L E A N

W E L L E S S-1 10 H PJ U B A R T E


E S P S ys te m – 9 0 0 H P – 2 50 0 0 b p dE S P S ys te m – 9 0 0 H P – 2 50 00 b p d

D P R – 5 .6 2 5 ” I DD P R – 5 .6 2 5” ID

1 0 7 0 m1 0 7 0 m

1 5 0 0 m

1 5 0 0 m

1 3 0 0 m

1 3 0 0 m

F P S O - S E I LL E A NF P S O - S E IL L E A N



E S P S ys te m – 9 0 0 H P – 2 50 0 0 b p dE S P S ys te m – 9 0 0 H P – 2 50 00 b p d

D P R – 5 .6 2 5 ” I DD P R – 5 .6 2 5” ID

1 0 7 0 m1 0 7 0 m

1 5 0 0 m

1 5 0 0 m

1 3 0 0 m

1 3 0 0 m

Main objectives:

Test production technologies at 1700 m water depth

Investigate multiphase flow at low temperatures (gas-lift)



12 OTC15283

Figure 8 – Cross section along the horizontal well length in a viscous oil reservoir with bottom aquifer.

Figure 9 – Water saturation after 6 months and 10 years of water injection. Injector-producer spacing of 900 m.

Figure 10 – Water saturation after 6 months and 10 years of water injection. Injector-producer spacing of 450 m.

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