Copyright 1997, Society of Petroleum Engineers, Inc.

This paper was prepared for presentation at the Fifth Latin American and CaribbeanPetroleum Engineering Conference and Exhibition held in Rio de Janeiro, Brazil, 30 August3September 1997.

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Abstract

AbstractThe first question that arises when deep water completion(DWC) is discussed is the definition of deep water. Thisconcept varies from company to company but Petrobras isconsidering deep water from 600m to 1200m water depth.From that depth until 3.000 m is ultradeep waters. DWCcomprises many special equipment, mostly hydraulicoperated. Most of the equipment under consideration in thispaper may be similar to shallow water completion with WetChristmas Tree (WCT) already installed but expertise, fieldexperience and wide vision is crucial because the problemsare fully different. This technical paper deals exactly withthis subject. It intends to show few of the failures thatPetrobras had in the last years with deep completion usingwet christmas tree system. But more important than showingthe failures or problems, the point is to analyze the solutionthat was given to all the problems. Knowledge, creativity,teamwork and patient were the basis for deriving thistechnology leader in the world.

IntroductionDeep offshore completion is still a rather new technology inour petroleum engineering world and many critical pointsstill are under research(1). We could say that only in the last3 years the 1.000m water depth was overcome mainly incountries as Brazil and the USA. In Brazil, the discovery ofMarlim, Albacora, Bijupira, Salema, Caratinga and recentlyRoncador fields in Campos Basin made possible for theBrazilian government petroleum company Petrobras to invest

in deep water production technology(2) . This paper willdiscuss only part of the production technology which is thecompletion engineering related solely to wellhead equipment.Wellhead equipment we mean all production equipment thatare installed from the wellhead connector to the wellchristmas tree. This includes multifarious equipments as (1)Housing for the permanent drilling base; (2) ProductionAdapter Base and running tool; (3) Production TubingHanger and running tool; (4) Wet Christmas Tree; (5) WCTTree Cap and running tool; (6) accessories as CompletionRiser, Terminal Head and Corrosion Cap (Fig. 1). In deepwater drilling and completion, most of the incidents whichresulted in rig loss time in the last 7 years were collected in aspecial report called ROA or Report for AbnormalOperations. More than a 1.000 ROAs form a specialdatabase which comprises field experience of Petrobras intreating different problems in drilling and completion in deepwater and, more important, the analysis, solution andrecommendation for each case. In this technical paper fewcases where selected for presentation trying to cover most ofthe equipment /technique already cited.

Main Production Wellhead EquipmentsIn this paragraph the main production wellhead equipmentand components will be briefly described. The objective is toindicate how the equipments look like, how they work,common sizes and main parts (3).

Drilling Housing. The drilling housing is part of thepermanent drilling guide base and is connected to the top ofthe 20 in. casing (Fig. 2). In deep waters , the standardnominal external diameter is 16 in. After cementing the 20in. casing, the housing stays about 2 m above the mudline andhas the following purpose: (1) to hold up the 20 in. casing;(2) to be a seat for the next casing hangers; (3) to provideconnection and support for the Blow Out Preventer (BOP).This housing has a H-4 profile which will allow the BOP H-4connector to hold and resist hydraulic pressure, weight andmechanical stresses (Fig. 3).Ring Gasket. One important accessory in the housing is thering gasket adjusted at the top in a groove, as shown in fig03. This ring is activated by compression applied by the H-4connector in the housing and should provide metal-to-metal

SPE 38964

Deep Water Completions in Campos Basin: Problems and SolutionsB. Plavinik, SPE, R.B. Juiniti, M.T.R. Paula, and R. Dias, SPE, Petrobras E&P BC

2 B. PLAVINIK, R.B.JUINITI, M.T.R. PAULA AND R. DIAS SPE 38964

seal between both parts. The ring gasket has different profiledepending on the necessity and we will see, in this paper,how to prevent leaking if the top of housing becomedamaged.

Production Adapter Base (BAP). It is the first equipmentinstalled in the completion phase of a subsea well and it islanded and locked into the wellhead with the 16 connector. The BAP is the equipment prepared to take in thetubing hanger, the WCT and the flowline hub in such a wayto allow the simultaneous connection of the WCT to the welland to the flowline. Basically the BAP is compounded by thefollowing equipments: (1) one H-4 connector which will latchin the housing of the drilling base; (2)a H-4 profile in the top which will allow the latching of theWCT; (3) internal helix to orientate the TH and (4) a cradleto support the flowlines. In deep water and with the WCTused it is necessary to land the tubing hanger in a certainazimuth because of the flowlines orientation. The orientationof the flowlines depends on the engineering project fordevelopment of the field because many factors have theirimpact as position of the production platform and thestorage/download production vessel (FPSO), size of theflowline, water depth and others. Another point is that thestandard production subsea equipment which is 16 in. Itmeans that if the drilling housing is 18 in. it will benecessary to set the BAP for the standard production 16 housing. The third point is the flowline hub which containsthe production and annular bores and control lines (downhole safety valve, WCT control lines, etc.). The productionhub launched with the flowline must be inserted in thecradle which is part of the BAP. For those reasons it isimportant to set a permanent production base; the tubinghanger and the WCT will be both landed and locked in theirproper place in the BAP, as shown in Fig. 4. Running Toolfor the BAP. There is a special tool to run, set and latch theBAP. It is called FIBAP. The FIBAP is run in drill pipe withthe 6 functions umbilical hydraulic hose. The mainfunctions of the FIBAP are: (1) to perform a function test inthe BAP at the surface; (2) to run and latch the BAP in thedrilling housing according to a specific orientation; (3) topressure test the connection with the housing against acement ormechanical plug in the well; (4) to retrieve the BAP ifnecessary. The FIBAP is also used to perform the verticalconnection which is the connection of the flowlines to theBAP from a provisory skid that is deployed close to thewellhead by a service pipeline deployment ship. Oneimportant issue in the FIBAP is the EDS or the EmergencyDisconnection System. This system is a absolute requirementfor working in Dynamic Positioning Rigs. If, for any reason,the rig has a drift off or a drive off the EDS will release theFIBAP from the BAP in a matter of seconds, standing therig for free movement.

Tubing Hanger (TH). The subsea tubing hanger is used formany reasons as: (1) to support all the weight of theproduction string; (2) to provide access to the annulus of thewell in case of gas lift or other reason; (3) to isolate the wellfrom the wellhead equipment; (4) to allow temporaryabandonment of the well already equipped for production ifthe WCT is not ready for installation. Tubing hanger is avery important issue in deep water completion. It is hydraulicoperated and latches inside the BAP bya retaining ring, driving, at the same time, a sealing ring forisolation. It has a 4 in. production bore, a 2 in. annulus boreand two bores for down hole safety valve control lines.Petrobras uses TH size 16 in as shown in Fig. 5. The TH isrun in a Tubing Hanger Running Tool (THRT) as in Fig. 6.The main components of the TH are: (1) The retaining ring;(2) the sealing ring; (3) the annulus check valve and (4) thebody itself which holds the production and annulus bores.Tubing Hanger Running Tool(THRT). It is a hydraulicoperated tool which will allow the landing, latching andunlatching of the TH in the BAP. The main components are:(1) Main body with vertical connections to the production andannulus bore and hydraulic control lines; (2) Upper edge forcompletionriser connection; (3) Lower edge with stabs for connecting theTH; (4) Hydraulic system for latching to the TH sleeve andbody and (5) External lower sleeve with a castle profile toorient the penetration of the TH in only one position avoidingdamaging the sealing area of the stabs.

16 in Wet Christmas TreeThe WCT is a completion equipment installed on thewellhead and has the finality to control and direct the flow offluids produced or injected in the subsea well (Fig. 7). TheWCT used in deep waters is guidelineless (GLL) and is verymuch standartized(4). The well can produce to the workoverrig throughout the completion riser or to the productionplatform in a normal operation, operated remotely. The mainparts of the WCT are:A) Central Connector: It is like a H-4 connector. It workshydraulically by locking in the wellhead housing by a camering and slips mechanism. It has a VX 16 gasket ring toprovide sealing against the housing. The connector has stabsfor the production bore, annular, DHSV and the electrictransducer. It is dimensioned to support all the operationstresses as internal pressure, shear and tension stress. B) Valve Blocks. It comprises a production size with 41/16 in. x 5.000 psi master, swab and wing valves and thesame assembly for the annular loop with 2 1/16 in. x 5.000psi valves. It has a 2 1/16 in. x 5.000 psi crossover valveabove the master valves. All valves are gate type with metal-to-metal seal and hydraulic functioning with a fail safe closesystem. Besides that the valves can be operated with aoverride mechanical system using a Remote Operated Vessel

SPE 38964 DEEP WATER COMPLETIONS IN CAMPOS BASIN: PROBLEMS AND SOLUTIONS 3

(ROV), if the hydraulic system presents failure.C) Flowline Connector. The flowline connector promotes thecoupling between the WCT and the flowline hub allowing theflow of fluids from or to the well, as well as hydraulic controland electric signal from the pressure and temperaturetransducers. It works similarly to the Central Connector,which means that it has a slips and dogs actuated by a camering that goesup and down depending on the pressure of the hydrauliccylinders. It can be unlock mechanically with a ROV if thehydraulic system failures.D) Reentry Mandrel or Tree Manifold. It has a workingpressure of 5.000 psi with a hub top preparation for 13 5/8 in.to receive the Tree Cap or the Tree Running Tool. The top ofthe hub has the 4 and 2 in. production and annulus bores,sealing bores for hydraulic control connections of therunning tool, tree cap or even the corrosion cap. Externallythe Tree Manifold has a slot for orientation of the reentryfunnel.E) Reentry Funnel. It is a funnel up type, mounted on top ofWCT to guide and orient the fitting of the tree cap and theWCT Running Tool in the Reentry Mandrel. If, for anyreason, the funnel is damaged, it can be removed by ROV atthe bottom of the sea by actuating three levers positionedaround the funnel.F) WCT ROV Panel. This panel is placed in the front part ofthe WCT and works as a mechanical override for the WCTvalves, including the DHSV lines. It is designed to beoperated by the mechanical arm of the ROV.

Tree Cap. It is installed on the top of the tree and has themain purpose to connect the umbilical hydraulic lines thatcontrols the WCT functions, allowing the WCT to becontrolled by the production platform. Besides that, the TreeCap is used as a second safety barrier for the production andannulus bores throughout the metal to metal seal. The mainparts are the 13 5/8 connector, the upper extremity in 13 5/8x 5.000 psi API hub, the guide funnel, orientation pins, backup panel for commutation of hydraulicfunctions of the WCT and hydraulic circuit.Tree Running Tool. The Tree Running Tool is used to run theWCT Tree Cap. It has a profile on the top which allows theconnection of a reinforced joint of completion riser also calledstress joint, that is used to run WCT in deep waters. Besidesthe standard hydraulic circuit operated by a hydraulic bundlewhich operates all functions of the tree and DHSV, it has asecondary hydraulic circuit operated through the control linesof the completion riser which will unlatch the running toolfrom the tree if the hydraulic bundlebreaks.

Completion Riser. The completion riser comprises a 4 and 2in. bores which will access the production string and theannulus, covered by a 9 5/8 in. casing pipe. It also has 6

hydraulic control lines which will perform the operations oflatching and unlatching the TH from the THRT and operatethe DHSV (Fig. 8).

Corrosion Cap (CCAP) The corrosion cap is a devicepositioned on top of the drilling or production housing inorder to protect the housing sealing surface from damagecaused by seashell or shellfish deposition. It is available in 16 or 18 in. sizes and has the following main parts: (1)lower body with funnel; (2) Central guide post; (3) Externalsupporting cables; (4) Internal supporting structure and (5)Internal rubber cap. Usually the CCAP is landed andretrieved with a hook tied in a 5 in. Drill pipe crossoverwith 5/8 in. steel cable. Most of the times this is a simpleoperation which is assisted by ROV. The CCAP can belanded or retrieved also with a running tool since the centralguide post has a top profile but this procedure is not common.

Terminal Head. The terminal head is like a double christmastree positioned on top of the completion riser. The mainfunctions are to control the flow of fluids from the well, toallow safety wire line or coil tubing operations and gas ornitrogen injection throw the annulus. It has a 4 and 2 in.production and annulus bores. The 4 in. valves are: master(hydraulically or manually operated), swab and wing. The 2in. Valves are: master and wing. Normally the terminalhead is 5.000 psi working pressure rated .

Riser Shear Joint. Drilling and completion in DynamicallyPositioned (DP) drill ships is a very safe operation butsometimes there is the risk of driving off the location becauseof problems in the DP system. The problems may be electricenergy generation, bad weather with a high heave or highsurface marine current and many others. When this problemoccurs, the red alarm procedure is to close the shear ram,release the lower marine riser package and allow the ship todrive off until situation is under control again and positioncan be restored. If the completion riser is inside the BOP, itwill be impossible to close the shear ram since this risercomprises a external 9 5/8 in. casing and internally a 4 in.and 2 in. Production tubing. For that reason, Petrobrasstarts using a Riser Shear Joint which stays inside the BOPduring completion riser operations (Fig. 9). This shareablejoint is a 4 in. production pipe in which the 2 in. Annulustubing is replaced by 3/8 in. steel tubing and all otherhydraulic hoses are tied to the shear joint mandrel. Using thistool it is possible to close the blind ram in case of emergency.After shearing, the fish can be retrieved with a specialretrieving tool which grabs the tubing hanger running toolright below the riser shear joint, and applying pressure to theannulus above the tubing hanger, the THRT can be releasedfrom the TH.

Case Histories

4 B. PLAVINIK, R.B.JUINITI, M.T.R. PAULA AND R. DIAS SPE 38964

In the next paragraph we will be describing case historiesthat arisen during the completion of deepwater wells inCampos Basin, offhore Rio de Janeiro State, Brazil. Fewoperations were selected each one trying to cover acompletion equipment already described in the previouschapter. Each one had a solution and a lot of learning wasachieved. This experience and learning we want to sharewith the readers. We will try to separate each case in threesteps: the problem, the consequence and the solution that wasadopted.

Wellhead Jetting Cleaning Tool (WJCT)Problem: After a temporary abandonment, the wellhead,even protected with a corrosion cap, is subjected to veryaggressive environment. It may cause damage to the sealingarea of the wellhead connector or even to the top of the tubinghanger, already set and tested. This damage is characterizedby sea shell or conch shell or scallop deposition and needs tobe removed by a jetting mechanical device. Consequence: Failure in the pressure testing of the cavityinside the wellhead connector. It may happen when aProduction Adapter Base (BAP) is set on the top of thedrilling connector, or when the Blow Out Preventer (BOP) orthe Production Wet Christmas Tree (WCT) is landed on thehousing and a VX type ring is compressed against bothsealing area (upper tool and lower connector).Solution: A WJCT was designed for 16 or 18 housing insuch a way that it could jet and clean only the sealing areasof the wellhead connector and the tubing hanger and havingother important characteristics as: (a) strong designadequately to resist the stresses from the drillpipe torque,rotation, sea current effect, etc, (b) removable inverted funnelto fit on the most common size of wellhead connectors, (c)the jets diameter were designed and positioned in the tool toprovide maximum cleaning action under usual pumping rates.Figure 10 shows the WJCT and the main parts as jetting sub,body, guide funnel and jetting.

Subsea Sealant Injector (SSI)Problem: During the late 80s a different style of tubinghanger was usedin the completion of few subsea wells. Ithad a 4 in. production bore and a concentric annulus foraccessing the annulus of the production string. Similar tubinghanger, from other factories, had a distinct 4 and 2 in boresand it was necessary to install a 1.81 in. blanking plug in theannular line for safety during installation of the subsea tree.But it was not necessary in this concentric tubing hangerbecause it had a Annulus Subsea Safety Valve (ASSSV). Butit was verified that was not possible to gas lift because theASSSV was leaking and could not stand open.Consequence: Costly workover. In order to fix the ASSSV itwas necessary to pull out the Subsea Tree and the productionstring. This would imply in killing the well, control fluid lossand the possibility of damaging the formation. Furthermore,

as a second barrier, it was necessary to set a mechanicaldevice to isolate the well.Solution: It was designed and builted a Subsea SealantInjector which was coupled to the Subsea Tree with divers inthe annulus flow loop. This tool was filled with a special 1,5liter capacity special sealing paste which was injected to theannulus port of the tubing hanger by pressuring the ASSSV.Keeping this valve in the opening position would allow theinjection of gas to the annulus port of the tubing hanger. Fig11 shows the equipment and main components.

Hydrate in the WCT.Problem . The well equipped with a WCT stop producingand a workover rig was assigned to identify the reason forthat abnormality. The production platform, who wasconnected to the well, had not reported any problem with thehydraulic control of the tree. During the operation andtesting, it was concluded that hydrate had formed inside theWCT and above the DHSV, blocking oil production.Consequence: We had two important consequences: (1) oilproduction loss due to hydrate blocking and (2) theassignment of a dynamic positioned semi submersible toworkover the well during approximately 4 days.Solution: A 3.000 psi pressure was applied to the 4 in.production bore in the completion riser with both swab andannulus valves open to the production platform. A rockingoperation was done ( press/depress) several times untilcommunication was established between the workover rig andthe production platform, indicating the de-obstruction ofWCT. Hydrate above DHSV, about 6 ft, was broken usingthe wire line sand bailer.

Unlatching the Tubing Hanger Running Tool (THRT).Problem: The production string was run with tubing hanger,THRT, Riser Shear Joint, completion riser and terminal head.The Tubing Hanger was landed, latched into the BAP andpressure tested, all positive. After all tests were concluded,started the unlatching of the THRT from the TH bypressurizing the unlock hydraulic line throughout thecompletion riser. But it was not possible to get an increase ofpressure because the fluid was circulating inside thecompletion riser. At that time it was concluded that the 3/8in. hydraulic line was ruptured inside the completion riserand it wasnt possible to get sufficient pressure to make theTHRT to work properly and be released from the TH.Consequence: Since it was not possible to retrieve only thecompletion riser with the THRT, it was necessary to unlatchthe TH and pull out all the production string until the THRTwould reach the rotary table. Furthermore some procedurehad to be done in order to identify which completion riserjoint had the THRT disconnection hydraulic line broken. Theproduction string with gas lift mandrels, extension joints anddown hole safety valve was all tested. The TH was tested toowhich meant a very costly operation with a minimum of 5

SPE 38964 DEEP WATER COMPLETIONS IN CAMPOS BASIN: PROBLEMS AND SOLUTIONS 5

days duration.Solution: The solution was obtained by closing the annularram of the BOP around the completion riser and very quicklypressurize the annular between the ram and the tubing hangerwith 2.000 psi, while maintaining a 4,000 lb. overpull in thecompletion riser. This solution was obtained just because theriser shear joint have a safety port to release the THRT fromthe TH in case of an emergency, like a rig disconnection andthe closing of the BOP shear ram. The THRT had anotherport with a check valve to hold the tool locked in the TH. Thepressure loss in the check valve was enough to make theunlatch function faster than the latching. It really happened. Leaking in the VX ring of the Production Adapter Base.Problem: The Production Adapter Base (BAP) was run, set inthe drilling housing and tested with 2.700 psi for 10 minutes.After BOP was installed the well was pressure tested againstthe closed shear ram and a surface cement plug with 2,700 psiand a leaking was observed. The pressure dropped to zerovery fast.Consequence: A retrievable packer was set right below the 95/8 in casing hanger and pressure tested with a positiveresult. The leaking was at the wellhead. The BOP was pulledout and the BAP running tool was latched again to the BAPand all the standards pressure testes were repeated but withleaking, apparently in the AX gasket ring. Later on it wasobserved a notch in the upper sealing area of the housing,probably caused by small seashell pieces that caused excessivestress in the housing taking into account the weight of theBOP.Solution: A new AX gasket ring was used but now with a leadinsert which allowed a little deformation in the ring, coveringthe damage area of the housing and providing enough metalto metal sealing.

Drop Out of Flowlines Manifold Cap.Problem: It was decided to pull out the flowlines after a wellwas already producing. The WCT was retrieved and theProduction Adapter Base Running Tool (FIBAP) was landedin the BAP. The operation was to unlatch the FlowlinesManifold (LMF) from the BAP, install the MLF Cap and putthis set in the flowline cradle. Before unlatching the MLF itwas noticed that the cap was not in the FIBAP. The Capliberation from the FIBAP is hydraulically operated from thecontrol panel at the surface and it was not actuated.Consequence: The FIBAP had to be pulled out for inspectionand it was observed that an O Ring in the pilot valve whocontrols the cap liberation was damaged and the function wasactually actuated by hydrostatic pressure of sea water sincethe O ring was leaking. Solution: The O ring was replaced, the FIBAP was againinstalled and the operation was successfully completed.

Corrosion Cap stuck in the drilling housing Problem: The well in Marlim Field was drilled and

abandoned for further production with corrosion cap (CCAP)installed in the drilling housing. For the well completion, thefirst operation was to retrieve the corrosion cap. This type ofcorrosion cap had a internal rubber cap to protect the sealingarea of the housing. The cap fits very close to the internaldiameter of the housing. Many attempts were done to pullout the corrosion cap from the housing using a conventionalhook but without success.Consequence: During the attempts, the outer slings of theCCAP were broken by tension. A new tool with two hookshad to be designed in order to dislodge the CCAP withoutdamaging the inner structure ( 1.0 in steel bars) otherwise itwould be impossible to retrieve it with a hook. It would benecessary a fixed structure in a drill pipe to latch in thecentral post of the CCAP and this operation in almost 800 mof water depth is very complicated.Solution: The double hook assembly was run with drill pipeand steel cables and connected to the inner structure with thehelp of ROV. It was necessary an overpull of approximately10,000 lb. to release the CCAP. When analyzing the tool, itwas observed that the rubber cap came completely damagedand the cause of this problem was the differential pressurebetween the interior of the housing and the hydrostatic of thesea water. The solution itself was to make two 5/8 in holesinternally at the rubber cap to avoid this differential pressure(Fig. 12).

BAP Damaged by Tubing String (with TH) Jump Out.Problem: In a Marlim field well, the tubing string withtubing hanger, tubing hanger running tool and completionriser dropped out due to a mechanical problem in the runningtool. The tubing hanger with all tubing string connected fellfrom approximately a 60 m height inside the BAP, damagingthe grooves that render orientation to the TH itself.Consequence: It was necessary to fix the grooves withoutpulling out the BAP otherwise it would be impossible to setthe TH in the proper orientation according to the submarineflowlines launching project. It is important to remember thatthe TH had two bores: 4 and 2 inches and they must beoriented. Solution: As shown in Fig. 13 It was put together a 6 junk basket, a 9 centralizer and the wear bushing with thewear bushing running tool (WBRT). In the WBRT, at thelower lateral bottom, it was molded tungsten carbide inserts .This tool was run and worked inside the BAP and theproduction housing with low weight and rotation. After thisoperation, the production string with TH was assembled againand the TH was set and pressure tested without any leak.

Vertical ConnectionProblem: It was noticed that in certain vertical connectionsoperations, the flowlines were severely damaged close to theparachutes which are installed to make the flowlines lighterto allow the movement from the temporary skid to the BAP. It

6 B. PLAVINIK, R.B.JUINITI, M.T.R. PAULA AND R. DIAS SPE 38964

was verified that the damage of the lines was caused by excessof compression force during the movement of the lines. Thewaves in the lines caused by the parachutes created somecompression force in the lines. With the movement of thelines, the maximum compression force was exceeded.Consequences: The flowlines had to be removed and replacedcausing delays not only in that particular well as in alldevelopment project of the field.Solution: The change of the position of the temporary skidrelative to the well head solved the problem. Formerly theskid was positioned in front of the cradle of the BAP,nowadays the skid is positioned beyond the cradle in one ofthe sides of the BAP. When the flowline is released from thetemporary skid , the compression forces caused by the wavesbrings flowline hub together to the BAP.

Retrieving a WCT with the tree cap installedProblem: The WCT for shallow water had tree cap with 4 in.and 2 in. Bores end plugs in the tree manifold that madepossible to access the well in case of killing and slicklineoperations. In WCT for deep water the plugs were eliminatedand the tree cap became blank acting as a second barrierabove the swab valves. In an early workover to clean theflowlines in a WCT at 752m water depth , it was perceivedthat the tree cap could not be removed because the unlatchingsystem was not working. The reason was the formation ofhydrates inside the latching mechanism of the tree cap. Thisoperation was concluded just before finishing this paper.Consequences: This well could be lost in the future dependingon the needs to control, for example, water influx into thereservoir, since it was impossible to retrieve the WCT andworkover the well.Solution: The hydraulic system of the WCT was modifiedallowing the unlatching of the tree even with the tree capinstalled. A special tool was designed in Petrobras RD Centerto be run with an ROV, that would grab in the control lines,capable of cutting, hydraulicaly seal and to apply pressure tounlatch the tree. This operation was really done and the treewas retrieved to the surface. As expected, nothing wasobserved in the mechanical system of the tree, confirming thehydrate formation.

Retrieving the cap from the flowline hubProblem: When is used the Vertical Connection System toland the flowlines into the BAP, it is common to set up a capabove the flowline hub which has the following functions: (1)to test the flowlines after deployment or connection to theBAP; (2) to provide connection of the FIBAP to the flowlinehub and (3) to protect the flowline hub if the WCT is not runimmediately. This is designed to unlatched from the flowlinehub and retrieved with a maximum of 5,000 lb overpull. Inour case, in a Albacora well, it was pulled with 30,000 lboverpull without releasing.Consequence: Many hours were spent trying to remove the

cap even when the hydraulic lines were pressurized from theproduction platform.Solution: The flowlines were tied up to the productionplatform but not yet connected. Anyway the flowlines bores (4and 2 in. ) were still sealed only for protection. The solutionwas to de-ballast the production platform and open theflowlines to atmosphere. This simple procedure allowed theretrieval of the cap. For that reason, the technical procedurewas modified to avoid such occurence.

ConclusionsOnly few cases were reported in this paper but sufficient toreveal that offshore completion with wet christmas tree indeep water involves several peculiar equipment and complexmethodology and the operation itself may not work accordingto the service company manuals. Many tricky problems maytake place, some of them on account of mechanical failuresor even man cause errors. It is a constant do and learnsituation and Petrobras is learning every moment, every tshould not happen like this situation. There is not a definiteconclusion. Each case exhibited a solution or a conclusionand we hope that these solutions, if applied by othercompanies, will save rig time and contribute to a betterengineering technology.

NomenclatureASSSV = Annulus Subsea Safety ValveBAP = Production Adapter BaseBOP = Blow Out PreventerCCAP = Corrosion CapDHSV = Down Hole Safety ValveDP = Dynamically PositionedDWC = Deep Water CompletionEDS = Emergency Disconnection SystemFIBAP = Production Adapter Base Installation ToolGLL = WCT guidelinelessH-4 = Type of Wellhead ConnectorMLF = Flowlines MandrelROV = Remote Operated VehicleSSI = Subsea Sealant InjectorTH = Tubing HangerTHRT = Tubing Hanger Running ToolVX/AX = Types of rings used in the wellhead connectorWB = Wear BushingWBRT = Wear Bushing Running ToolWCT = Wet Christmas TreeWJCT = Wellhead Jetting Cleaning Tool

Acknowledgments

We thank Petrobras for support and permission to publish thispaper. We also express our gratitude to all subsea engineersand technicians who were involved in subsea operations forthe last years and helped to supply material and information

SPE 38964 DEEP WATER COMPLETIONS IN CAMPOS BASIN: PROBLEMS AND SOLUTIONS 7

to gather this paper.

References1. Formigli Filho.J.M. and Ribeiro, O.J.S.: CriticalPoints for the Project of Very Deep Subsea Completions,paper OTC 5809 presented at the 20th Annual OTC in Houston, TX, USA, May 2-5, 1988.2. Ribeiro, O.J.S., and Costa, L.A.G.: DeepwaterSubsea Completions:State of the Art and Future Trends, paper OTC 7240presented at the 25 th annual OTC in Houston, TX, USA, 3-6May, 1993.3. Moreira, J.R.F. and Viegas, A.F.: GuidelinelessCompletion Offshore Brazil, paper OTC 5975 presented atthe 21 st Annual OTC in Houston, TX, USA,May 1-4, 1989. 4. Paula, M.T.R. and Moreira, C.C.: Deep Water X-MasTree Standardization - Interchangeability Approach, paperOTC 901 presented at the 27 th Annual OTC in Houston,TX,USA, 1-4 May 1995.

SI Metric Conversion Factorsin. x 2.54 E+00 = cmlbf x 4.448 222 E+00 = Npsi x 6.894 757 E+00 = kPa

Fig. 1 - Typical Configuration for deepwater completion showingthe main componentes: Wet Christmas Tree, Tree Manifold, TreeCap and Tree Running Tool.

8 B. PLAVINIK, R.B.JUINITI, M.T.R. PAULA AND R. DIAS SPE 38964

Fig. 2 - Petrobras deepwater wellhead stackup, showingthe high pressure housing and the orientation funel where theBAP inserts.

Fig. 3 - Typical H-4 16 connector showing the main componentsand the VX ring in position.

Fig. 4 - Production Adapter Base - BAP and main partsand showing the drilling wellhead housing being replaced bythe high pressure production housing.

Fig. 5 - Hydraulic Set Tubing Hanger Assembly.

SPE 38964 DEEP WATER COMPLETIONS IN CAMPOS BASIN: PROBLEMS AND SOLUTIONS 9

Fig. 6 - Tubing Hanger set and locked in place, inside the highpressure production housing, showing the production 4 in. boreand the annulus back-pressure valve.

Fig. 7 GLL subsea tree for 1.800 mwater depth.

10 B. PLAVINIK, R.B.JUINITI, M.T.R. PAULA AND R. DIAS SPE 38964

Fig. 8 Completion Riser showing main parts, as 4 and 2in bores, alignment key, control lines, lock ring and lockgroove ring.

Fig. 9 - Shearable Riser Joint.

Fig. 10 - Well Jetting Cleaning Tool project.

SPE 38964 DEEP WATER COMPLETIONS IN CAMPOS BASIN: PROBLEMS AND SOLUTIONS 11

Fig.11- Annular sub sea safety valve project.

Fig. 12- Typical corrosion cap 16 used to protect the wellheaddrilling housing.

12 B. PLAVINIK, R.B.JUINITI, M.T.R. PAULA AND R. DIAS SPE 38964

Fig. 13- Main tools used to repair the damaged inner productionhouse.