OTC 17055 Drilling and Completion – How to accomplish CAPEX and schedule managing up to six rigs, simultaneously. P.S. Rovina and G.R. Borin, Petrobras Copyright 2005, Offshore Technology Conference This paper was prepared for presentation at the 2005 Offshore Technology Conference held in Houston, TX, U.S.A., 2–5 May 2005. This paper was selected for presentation by an OTC Program Committee following review of information contained in a proposal submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Offshore Technology Conference and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Offshore Technology Conference, its officers, or members. Papers presented at OTC are subject to publication review by Sponsor Society Committees of the Offshore Technology Conference. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Offshore Technology Conference is prohibited. Permission to reproduce in print is restricted to a proposal of not more than 300 words; illustrations may not be copied. The proposal must contain conspicuous acknowledgment of where and by whom the paper was presented. Write Librarian, OTC, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435. Abstract The success of an offshore oil field development strongly depends upon the well drilling success. Historically, the development of wells is the part of the project scope that presents the highest deviations in cost and schedule, due to the associated geological risks and the complexity involved in each operation. To fulfill the sanctioned CAPEX, the Barracuda and Caratinga well team has used the best management techniques and state-of-art drilling and completion technologies, allowing the completion of the well campaign on schedule and in the budget. This project has 54 wells, being 32 for oil production and 22 for water injection, in water depths between 709 and 1119 m. The whole scope took 44 months, using, in average, four rigs to perform drilling and completion, with a peak of six rigs during ten months. Those rigs have drilled 143 km of borehole; 30 km in pay zones, most of them in a horizontal path. The main drives on the operational side were: safety as a priority, a well design kept as simple as possible, and a detailed program containing contingencies and risk analysis for critical operations and real time drilling monitoring to expedite corrections in the well path when facing unexpected results in the pay zone. On the management side, the critical analysis meetings covered the client requirements (productivity indexes established by the reservoir group) and guaranteed the performance of service companies and suppliers based on clear targets agreed at the beginning of the development. The paper focuses on the key success factors, such as: perfect integration between operator and service companies, use of new technologies with the support of specialists, and good project planning and control, structured according to the PMBOK - Project Management Body of Knowledge. Introduction The Barracuda and Caratinga fields are located in the Campos Basin, 160 km east of Macae, offshore Rio de Janeiro State, in Brazil (Fig. 1). The Barracuda field was discovered in April 1989; the reservoir contains 25o API crude and covers an area of approximately 233 km2, in water depths between 600 and 1100 m. The Caratinga field was discovered in February 1994; the reservoir covers an area of 260 km2, in water depths between 850 and 1350 m, and contains 23o API oil. The pressure and temperature are normal so the rigs hired for the project had 10 kpsi BOP and the maximum depth measured in a well was bellow 5000 meters. Aiming at reservoir uncertainty reduction, a production anticipation project – named Pilot System – was implemented. Three exploratory wells from Caratinga and eight from Barracuda were connected to P-34 FPSO (Floating, Production, Storage and Offloading ) and were in production between September 1997 and October 2002. The information and data acquired during that phase were valuable to optimize the location of the wells during the development phase. The Project was developed through a major turnkey EPC (Engineering, Procurement and Construction) Contract of over US$ 2.6 billion – including wells; subsea flowlines, umbilicals and pipeline; and two FPSO’s, P-43 and P-48 (Fig. 2). The well scope of work - drilling and completion – alone represented US$ 1.0 billion. The contract was signed in July 2000, making Barracuda and Caratinga one of the largest offshore development projects in the upstream segment. Despite being an EPC Contract, PETROBRAS remained responsible for the drilling and completion of the wells and a subcontract was celebrated between KBR (the EPC Contractor) and PETROBRAS (the Well Contractor) to accommodate the responsibilities. In this scenario, no delays could be accepted in the sanctioned well schedule and a dedicated team was built in July 2000. The drilling of first development well started in September and the formal asset structure was implemented in January 2001. Until May 2004, when the last well was completed, 5314 rig days were employed along these 44 months. If only one rig had been assigned to the project, 14.5 years would have been necessary to complete the scope. In fact, an average of four rigs were used, scaling up to a peak of six rigs during ten months. 2 OTC 17055 The scope The Project has a total of 54 wells (table 1) but only 44 were drilled in this scope: ten wells from the Pilot System were transferred to the permanent production system. Among these ten wells, three were converted to water injection wells and one was recompleted in another zone. The other six were directly transferred to P-43 (five) and P-48 (one), involving only the subsea scope, i.e. relaying of flowlines and hook up to production units. Field Oil Water Producers injectors Total Barracuda 20 14 34 Caratinga 12 8 20 Total 32 22 54 Table 1 – Wells scope of work The majority of the wells – twenty-nine – should be horizontals, according to the project basis, all of them requiring sand control. Nine multilaterals should be drilled and ten completed – one had already been drilled when the contract was signed. The Challenges The well project bases clearly pointed out the main issues the team should face during the development phase. Among them, the most important are: The well design: although the reservoir has good petrophysical properties, its small thickness required strict path control through the drilling of the horizontal sections. Most of the wells had a +/-3 meter tolerance gap for navigation through the pay zone, reaching an extreme of 1,5 meters in one well due to water contact proximity. The multilaterals: in order to maximize the reservoir recovery, bilateral wells have risen as a solution for both oil producers and water injections at irregular parts of the reservoir (Fig. 3). Multilateral completion associated with sand control in a subsea well dramatically increase the risk of failure. Level 5 -junction construction – the best in class at the time – generates debris that fall on a plug set for one leg isolation. To remove these debris and to fish the isolation plug, a careful coiled tubing operation is required and the risk of having the CT assembly stuck is quite high. At the beginning of the development of the wells, a bilateral one was lost due to a stuck coiled tubing and, later, screen failure. The hydrates: since the production units were not available during the well completion, the tree block should have a proper fluid resident, keeping the oil and gas from the production tubing away from the water left in the flowlines. The project control: the deviations in cost and schedule for subsea developments are frequently due to the well scope which presents the higher risks: the most relevant are the geological, the technological and the rig performance. One project with this magnitude has too many interfaces and, consequently, a high risk of over schedule or overbudget. The project manager had to control a group of actions, such as: the status of material procurement; legal and customs issues; subsea interfaces and interference of units – rigs, lay support vessel, diving support vessel, stimulation boat, supplies. Rig interference: during the period of higher activity, four dynamic positioned rigs, two anchored rigs and two DP lay vessels worked together in the site. The uncertainties in the dates of unit movements required a day-by-day critical schedule analysi. Christmas trees: for this project, some improvements were applied in the subsea trees. Only GLL (guidelineless) trees were used and the most important changes implemented were the unique VCM – Vertical Connection Module – and piggy back concept. The standardization was maintained, representing a flexibility for the schedule. Any tree could be installed onto different production bases, even if furnished by different manufacturers. Some delays were experimented during the qualification of tree components and during the fabrication of the trees. Nineteen wells had to be temporarily abandoned just after drilling and gravel packing due to the lack of tree bases. Meet the productivity and injectivity indexes. The economic feasibility of deepwater development projects is very much dependent on the high productivity of the wells. The drives were: maximize the productivity and injectivity and minimize the damage of the wells (skin factor). Strict control of fluid cleanness and maximization of well extension exposing clean sandstone became an obsession for the engineers. The Structure The team in the asset Well Interventions Manager. In charge of cost control, legal aspects, interfaces management, coordination of critical analysis and meetings within the asset, with the Well Services Operator Unit and service companies. Project coordinator. Responsible for controlling the schedule, managing the contract and technical interfaces. The selection process inside the company considered: strong experience in offshore well operations, solid background in project management and ability in negotiations. Drilling programmer. In charge of drilling planning, control and procedures update. Having only one specialist controlling the drilling program presents various advantages, among them the uniformity in procedures, technical memory and fast reaction to surpass unexpected difficulties. Completion programmer. With a strong experience in subsea completions, this engineer has controlled since the sand control operations until the Christmas tree installations. The same advantages listed for the drilling specialist are valid for the completion advisor, in addition to the control of a larger number of procedures to be applied in a very complex subsea scenario. Rig Coordinator. In charge of the everyday rig well supervision, this engineer had to guarantee the execution of the operations according to the reservoir requirements. Any change in the program or provision of additional resources had to be managed by him. His profile is: an experienced company man, assigned temporarily at the office to coordinate the rig OTC 17055 operations. Most of the times, these engineers coordinate two rigs simultaneously. Fluid coordinators. Two dedicated mud engineers were assigned to the asset during the whole well development phase: one for drilling fluids and other for completions, gravel packing and stimulations. They were responsible for both the program and the execution supervision, as well as the improvements in execution procedures. Company man. The “eyes” of the operator aboard the rigs, the company man has taken care of the supervision of well execution, including HSE and technical management as well as rig and well services control. Planning engineer. An essential support for the project coordinator, controlling the day-by-day performance indicators, such as: actual cost, daily progress and earned value, HSE indexes and the key performance indicators negotiated with suppliers and clients. During this development phase, the most important interface in the asset is the reservoir team, as well as the flow assurance and subsea team. The price of any new information required, any change proposed for scope resulted in an immediate economic analysis to evaluate its feasibility. This routine has reduced the change orders to a low and acceptable level. The supporting structure E&P Service Unit. This department has played an important role for the success in the Barracuda and Caratinga well development. Key people were assigned to support the asset in control planning, supply, logistics and technical solutions in the following areas: rig contract management, directional drilling, casing and cement, subsea equipment, completion equipment, slickline, wireline and coiled tubing operations, well testing and coring/fishing operations. Desk engineers. The service company has assigned dedicated desk engineers for sand control, well design and directional drilling. Asset support. HSE and legal advisors, quality assurance and project management consulting were also important support for the project manager. The Solutions Management. To face the sort of challenges pointed out above, the team has quickly established urgent actions and inserted them in an integrated action plan. The critical analysis meeting was the mechanism selected to control those actions. Initially the frequency was on a weekly basis and after one year, one meeting per fortnight was enough, given the level of commitment spread in the whole team. The methodology proposed in PMBOK Guide (Project Management Book of Knowledge) was intensively used for this project planning and control. The planning started three years before the EPC contract signature and has been revised by specialists to guarantee the best time and cost estimation, based on actual data already performed in a similar scenario. To select the KPI (key performance indicators), two drives were considered: minimum number, to reduce the time spent by the engineers for this matter, and focus on core subjects and operations. The main indicators were: 3 • Corporate and shareholders interest (negotiated with the asset manager) – cost, schedule and HSE KPI (lost time incidents and non-lost time incidents); • Client (negotiated with the reservoir manager) – an evaluation form was created, containing the main quality items prioritized by the client for the completed well: execution as per approved by the well design and damage ratio under two. • Drilling subcontractor – the asset has controlled the main service company through the MTBF (mean time between failures) for motors, LWD (logging while drilling) and MWD (measuring while drilling) equipment. • Sand control subcontractor – the targets were: 100% gravel placement and excellence in tool performance. • Rig subcontractor – a service protocol was signed with the PETROBRAS E&P Service Unit, which contros the rig contractors. The main KPI was the rig availability. The average performance at the end of project was above 93% of rig efficiency. Any failure in a given process led to a cause analysis and, depending on the results, one of the three following mitigation actions were taken: • Inadequate procedure – the division in charge of given procedure had to revise it and submit it to the asset advisor approval. • Human failure – immediate training was provided. • Equipment failure – improvements were immediately provided in the part that had bad performance. A risk management process was also implemented. The critical issues were revised weekly, evaluating the probability of occurrence, the severity and the ongoing actions for prevention or mitigation. For example, when a particular tree supplier was in trouble to deliver the equipment and the critical path would be affected – delay in project schedule – two other suppliers were called to manufacture two trees each one, in emergency (one year to deliver) to avoid any delay. Both suppliers accomplished the targets and no delay was experimented due to this risk. Drilling. The advances in the horizontal well technology, supported by the high quality of seismic data in the positioning and geosteering of the wells, improved the productivity indexes and enhanced the sweep efficiency of the oil, allowing the development of these fields and meeting the economic targets. The main drives were: • Safety, as a priority; • Credibility in the well operations program, i.e. no mistakes or omissions were allowed; • Well project kept as simple as possible; • Rig daily meetings to refine the operations risk analysis and the contingencies when something fails; • Wells drilled with real time logging and monitoring in the office to expedite decisions. The integrated action between the Well Intervention and the Reservoir Teams has assured rapid and transparent information flow, speed-up and optimized decision making. Well planning has considered the completion needs, e.g.: low doglegs and minimum sinuous in horizontal section to 4 OTC 17055 minimize problems when running in the sand control assembly. Slender wells. The first wells drilled had the “conservative” casing arrangement (Fig. 4), as following: Phase I Bit diameter (pol) 36 Casing (pol) 30 II 26 20 III 16 13 3/8 IV 12 ¼ 9 5/8 V 8 ½* 5 ½** or 7*** * ** *** Horizontal open hole Screens basepipe Directional cased wells As soon as it was confirmed that no shallow sands occurred in the Caratinga field, the slender concept was adopted, i.e. the 30” casing was set and the 16”phase was drilled without BOP. The 13 3/8” casing was set and anchored at high pressure housing. The time spent to drill the slender wells was about four days less than the conventional wells, reducing rig cost plus unnecessary casing and cement. An intensive use of technology allowed the short operator staff to control the project properly, focusing on decision making and spending no time to acquire or prepare data. Among the most valuable tools used, we highlight: • Bit inclination sensor – allowing fast track correction when the BHA (bottom hole assembly) began to deviate from planned target; • PWD (pressure while drilling sensor) – monitoring the mud ECD (equivalent circulating density), the driller had strict control of cuttings in suspension, optimizing the drilling rate with much less risk of the drill string getting stuck; • Well trajectory planner; • Conventional downhole motors plus rotary steerable systems; • Real time monitoring – acquisition and interpretation of profile, reservoir characteristics and pressure data; • Databases for seismic and geological interpretation. The bit inclination sensor, the rotary steerable and the real time monitoring have allowed a fast horizontal section drilling with lower sinuous and no rugosity. The PDC bit had an important role in complying with the tight schedule; in most of the wells one bit alone was able to drill the entire horizontal section of up to almost 1000 meters. Directional pilot wells were drilled for all the horizontal wells, providing important information on the reservoir for the best positioning of the horizontal section, for example: top and base of pay zone, lithology and pressure data. The real-time acquisition enabled quick and reliable decision-making for optimizing well path trajectories. The horizontal trajectory was always designed to maximize the use of existing pilot well. Sand Control. Thirty horizontal wells were completed with open hole gravel packing (OHGP). Horizontal extensions varied from 238 to 991 meters, with the average being 640 m, and an accumulated length of 19200 m. Vertical and directional wells were completed with frac-packs. The record for a subsea well was the four-zone selective frac-pack completion for tight spacing between zones1, performed in a vertical well in the Caratinga field. Thus, two paradigms were broken for open hole horizontal gravel packing: Water packing pumping at low flow rate. Best practices recommend pumping the gravel using high rates to guarantee the correct placement throughout the whole horizontal section. In one particular well, the expected fracture gradient was too low and, in order to prevent the risk of rat hole fracture, some simulations were carried out, and it was decided to reduce the rate in 40 %. The gravel was pumped at flow rates as low as 5,5 bbl/min and the 8 ½”open hole was 100% packed. Water packing in an injection well performed with no return. The gravel assembly was run into a horizontal section and the packer set. During the cycling of the one trip gravel packing tool, the open hole was swabbed and part of the mud cake was removed, causing severe formation losses. Various calcite peels were spotted but the losses remained. The gravel placement was carried out, pumped at 11 bbl/min with no return and the packing has reached 95%. After an acid job, the injection test showed no skin in this well. All the other wells were 100% packed. Completion. Completion string. The production string was 13 Cr, 5 ½” premium thread, except in four wells with higher flow rate where a 6 5/8” tubing was ran. All the wells were equipped with PDG (permanent downhole gauges) - quartz pressure and temperature sensor – and TPT – Tree pressure and temperature transducer – except the multilaterals. The production casing was 9 5/8” so the clamp for electric cable was designed to minimize the risk of incidents: perfect adjustment onto couplings, round shape to easily pass through BOP and wellhead and no bolts or nuts exposed to hit during the hole tripping. The water injection wells were equipped with BRV (back pressure and retainer valve) to avoid back flow just after any stop in the pumping during the operation phase. Typical production string composition and casing arrangement are shown for vertical well (Fig. 4) and horizontal well (Fig. 5). Stimulation. All the water injectors had to be acidized to remove the mud cake. In addition, some oil producers had presented a damage ratio above the limit after the gravel pack and had to be acidized. The corrosion inhibitors worked well during the acid treatment. However, the necessary back flow after treatment in oil producers kept the pH very low for a long period, raising the risk of corrosion in 13 Cr screens. One organic formulation – acetic mud acid – has mitigated this risk. Piggy back trees. (Fig. 6). To minimize the length of flowlines and control umbilicals, and to save connections onto FPSO, this concept was applied for water injection wells. The master base has two independent chokes so the flow rate in master well and in the slave well can be controlled separately anytime during the well life. There are pressure & temperature sensors and flowmeter available. The multiplex control pod OTC 17055 and both choke modules can be removed independently using a Lay Support Vessel, reducing workover costs. The Christmas tree and other accessories follow the GLL standardization. The slave well tree and adapter base are exactly the same used in other wells. Hydrates prevention. This issue was addressed by spotting diesel and alcohol inside the tree block. Ethanol was used in production trees and diesel in injection trees. This simple procedure avoids contact of gas and remained water near the tree wing valve during well kick-off. The previous experience shows that, even using foam pigs as spacers when displacing water by diesel in flowlines, the seawater is not completed removed. The ethanol inside the tree block doesn’t allow hydrate formation. Rig assignment and management Rig assignment. The rig cost represents approximately 70% of the overall well costs. PETROBRAS works in the Campos Basin with a pool of floating rigs – 25 in average during the Barracuda and Caratinga development – and this assorted fleet allows the company to optimize the rig assignment. The rig selection for this project considered: DP (Dynamic Positioning) drillships for drilling. They have good performance for drilling because the higher heave, row and pitch (compared to semi submersible rigs) don’t imply in downtime increase. The lower cost – again comparing to semis – has contributed to control the CAPEX. They were also used in completions except during winter time when the weather conditions become rough and the efficiency decreases. Three different drillships (Pelikan class) have worked for the project, with a maximum of two units at the same time. Anchored semi-submersible for multilaterals and completions. Bilateral wells require a very stable rig with lower cost, due to the risks during the sand control operations and the junction completion. Anchored semis match these criteria, especially after the advances in pre-lay anchoring. The total DMM (Demobilization, Movement and Mobilization) took two or three days. This additional time for rig moving had no impact in schedule and helped to control the CAPEX. Two anchored semis have worked in the Barracuda and Caratinga development, one belonging to PETROBRAS fleet and the other one contracted. DP semi submersible. They are suitable for subsea wells completions and very flexible for well abandonment in case of interference, stable enough for delicate operations such as running of sand control assembly, tubing hanger, production base and Christmas tree installation. Four DP semis were used in the Barracuda & Caratinga development but only one has worked throughout the project – the Ocean Alliance. Rig performance. Each dynamic positioned unit has a safety exclusion area where no other unit is admitted. This Restriction Diagrams, also known as “killer bubble”, considers an eventual drive off and the time to restart the unit control, under historical current and weather conditions. These restriction diagrams are in the 3rd generation and the software is an important input since the preliminary project – to optimize the well wellhead location – and during the construction phase for rig schedule control. . 5 The high rig efficiency in this project is due to two programs ongoing in the Rig Service Unit: • DPPS (Safety Program for Dynamic Positioning Rigs). This program establishes some procedures, regular tests and inspections to guarantee excellent performance of the whole DP (Dynamic Positioning) system. Since its implementation, in 1996, the number of incidents has been reduced in 50%. The main routines are: • The annual inspection which is the most important one as this procedure created an excellent practice allowing the rig crew to solve small problems right away. The main items inspected are: DP control, power generation, power management system and thrusters. The crew training status is also evaluated. • One important routine onboard is the register of any DP degraded status. The EDS (emergency disconnection sequence) criteria vary according to the water depth. The procedures establish different EDS sequences depending on how critical the ongoing operation is. These procedures anticipate the well abandonment in safe conditions and the cost and the safety impacts of an eventual disconnection. • Another regular test is the blackout simulation, evaluating how fast the crew ties the rig to a rescue boat and solve the problem, minimizing the drive-off time and consequently the risk of collision. • Rig inspection – The first inspection occurs at the beginning of the contract and analogously just after any system upgrade. All the rigs are also inspected once a year. The main rig equipment is tested to prevent failure during operations. Among them, BOP (blow out preventer), top drive, compensator, power generation, cranes, etc. The HSE obligations are also audited: safety equipment and procedures, hygiene, etc. To avoid interference between units – rigs, lay support vessel, diving support vessel and stimulation boat – a careful monitoring routine was established. Every week the schedule was updated and, sometimes, a conjunction of delay in operation in one rig and anticipation in another, led the project coordinator to change the sequence of interventions in three or four rigs. To minimize risks of units interference, one rig installed a new set of transponders with different frequency, allowing her to travel all over the fields with no chance of bad performance in the dynamic positioning control. Multilaterals. After the premature failure in one bilateral with gravel packing, just before the EPC period, an internal workshop was organized and some important decision were taken aiming at the reduction of this risk. • Change four water injection bilaterals in four pairs of piggyback wells. The prototype of piggyback tree adapter base was manufactured and available for application in another well. The estimated costs were similar with less risk for piggyback completion. New adapter bases were immediately ordered. • Two multilateral injectors and one producer became horizontal wells with longer section. 6 Special procedures were adopted to reduce the risk of failure for the remaining two bilateral-horizontal producers to drill and complete and for the directional to be completed: Dedicated team. Four months before the first well drilling, the team started to plan and review the actions for the execution. The drilling programmer has assumed the rig coordination and was supported by company men and well services advisors, all of whom had previous experience in bilateral construction. Dedicated rig. An anchored semi was assigned to these well drillings and completions because of its stability and lower cost. This rig was not committed with any other critical intervention so it was capable to absorb eventual delay in operations. Drill and complete well on paper. The team has established contingencies for all critical operations and exhaustedly reviewed the procedures and the well program. Simple production/injection string. The drive was: “less accessories implies less risk of failure”. No PDG was installed to avoid clamps and cables in completions. In case of an incident, any fish would drop onto junction leading to very complex fishing job and high risk of premature well failure. HSE. Besides the KPI monitored during the critical analysis meetings, a routine of monthly meetings with rig contractors was implemented. The public discussion of main incidents and their mitigation led to a “healthy concern” among the contractors. The daily safety meetings onboard also contributed for incidents prevention. The rig environment has plenty of accident risks and only a permanent discussion about the risks in each phase is able to keep people alert and consequently reduce LTA. Conclusions The good relationship with the reservoir team was one of the most important key-success factors. During the 3-½ years of development phase both teams have shared the risks and together decided the changes in the scope. If one new well leg were necessary, another one would be reduced or suppressed. The clear targets for cost and schedule have established a “cooperation agreement”. New technologies have played an important role by reducing risks and allowing the short number of engineers in the asset to make the best decision during the well construction phase. Some remarkable solutions were rotary steerable, at bit sensor, logging-while-drilling, one-trip gravel pack tools, and piggyback trees and real time monitoring. The very experienced specialists assigned by the Operator Well Services to the Project allowed a good planning before all activities and a fast decision-making when facing operational problems. The final cost of each pair of water injector piggy back wells was equivalent to the planning cost for multilaterals, in spite of the extra cost for the slave tree. The risk of failure was dramatically reduced. The workflow with the service companies has allowed both teams to focus on solutions and spend no time blaming each other for undesirable results. The well design has always been revised twice by both side’s specialists before a final approval of the drilling or completion programmer. OTC 17055 Shale intercalations in horizontal section represent potential risk of failure during sand control assembly installation. Marl intercalations are acceptable but shale frequently expands even if using inhibitors in drill-in or completion fluids, leading to premature well failure. In one horizontal well, even in the presence of 100 meters of continuous shale intercalation, the screens assembly was ran but remained stuck at an expanded shale section before reaching the final depth and a sidetrack was drilled. After this bad result, in similar scenarios, the leg with intercalations was abandoned and a sidetrack was performed with no more than four days added to the actual schedule. All of these aspects, allied to management, have resulted in cost and schedule accomplishment (Fig. 7), a remarkable performance for the well engineering in deepwater environment. Acknowledgements The authors thanks PETROBRAS for the permission to publish this paper and the contributions of: Luiz Ignacio Almeida, Marcos Lopes, Alexandre Pereira, Ricardo Queiroz, Afonso Pallaoro, Lee King, Rosane Vellasco and Flavia Fernandes. References 1. Vilela, A.; Hightower, C.; Montanha, R.; Oliveira, R.; Queiroz, R. and Pereira, A.; Deepwater Four Zones Selective Washpipeless Frac-Pack Completion Inside a Bad Cemented Liner: a Case History; SPE paper 90510, presented at 2004 ATCE – Houston, TX, USA. 2. Alves, Marcelo; Maciel, Walter B.; Reis, Leandro; Braga, Mario and Marques, João; Campos Basin Tertiary Reservoirs of Barracuda and Caratinga Fields: Development Strategy and Main Reservoir Management Issues; OTC paper 17053 - 2005. 3. Juiniti, Ricardo; Pallaoro, Afonso and Ohara, Shiniti – Restriction Diagrams: How to Work with DP Rigs in Close Proximity – OTC paper 8852, presented at OTC 1998. 4. Joia, Carlos JBM; Brito, Rosane; Moraes, Flavio; Barbosa, Benicio; Pereira, Alexandre e Marques, Luiz – Performance of Corrosion Inhibitors For Acidizing Jobs In Horizontal Wells Completed With CRA - Laboratory Tests; paper 1007, presented at 2001 NACE. 5. Nogueira, Emmanuel F.; Saliés, Jacques B. and Fartes, Evandro T. M. – Slender Well Drilling In Campos Basin. Paper presented at DOT 2000. 6. Emhjellen, Magne; Emhjellen, Kjetil and Osmundsen, Petter – Cost Estimation Overruns in the North Sea. Paper published in Project Management Journal, vol 34 – Mar 2003. OTC 17055 7 Figure 1. Barracuda and Caratinga fields Figure 4. Typical production string and casing for vertical wells Figure 2. Barracuda and Caratinga subsea layout Figure 3. Multilateral targets in Barracuda Figure 5. Typical production string and casing for horizontal wells 8 OTC 17055 Figure 6. Piggyback Christmas tree Figure 7. Cash flow: baseline, forecast in Dec 2001 and present