Management Since the discovery of the giant Tupi-Lula pre-salt complex in the Santos Basin of Brazil, explorers have been integrating new seismic technology advances with the fundamentals of regional basin geology to extend the pre-salt play across the Atlantic margin into deep waters and below the salt off the west coast of Africa. In 2005, Petrobras drilled a wildcat well on the Parati prospect in the deep waters of the Santos Basin, and encountered condensate gas below a thick layer of salt. The following year, Petrobras and its partners, BG Group and Galp Energia, announced that the Tupi wildcat, drilled to 16,060 ft in almost 7,000 ft of water, flowed at 4,900 B/D of sweet 30°API crude oil, 0.7 sulphur content, and 6.6 MMcf/D gas on a ⅝-in choke. This confirmed that a new geologic play had been discovered below the salt. Over the next few years, exploration efforts continued in this new pre-salt play, resulting in additional discoveries in the Santos and to the north in the Campos and Espirito Santo basins. Agencia Nacional do Petroleo (ANP) studies suggested that the charge and accumulation models for this new pre-salt cluster area of the Santos Basin contained reserves exceeding 30 billion bbl and possibly as large as 60 billion bbl of oil reserves. Though the thick layers of salt above the oil accumulations create challenges in seismic imaging and exploratory drilling, the salt has also served, through geologic time, as a superb seal that allows thick columns of oil to accumulate and be preserved. Many exploration companies have already constructed regional geologic and plate tectonic models that recognize that these world-class pre-salt hydrocarbon accumulations off the east coast of Brazil may have counterparts on the conjugate margin of the Atlantic Basin in the deep waters offshore Congo, Gabon, Angola, and Namibia. A geologic model from Cobalt International shows a cross section of the Atlantic rift system that predicts similar geology between the two margins (Fig. 1).

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 151186, ’Upgrading the Real-Time Drilling-Optimization Culture in Brazil's Challenging Deepwater Operations: The Utilization of a Remote and Rigsite Multidisciplinary Collaborative Concept,’ by Augusto Borella Hougaz, Danilo S. Gozzi, Isao Fujishima, and Klaus L. Vello, Petrobras, and Sandro Alves, Ian Thomson, Raul Krasuk, SPE, and Frank Buzzerio, Baker Hughes, prepared for the 2012 SPE/IADC Drilling Conference and Exhibition, San Diego, California, 6-8 March. The paper has not been peer reviewed. In Brazil, deepwater well-construction activity has increased significantly since the first major presalt discovery in the Santos basin in 2006. The creation of a multidisciplinary drilling-optimization group, integrated with the operator’s drilling team in 2008, and the introduction of a highly specialized downhole-drilling-dynamics measurement-while-drilling (MWD) tool changed the drilling-optimization concept in Brazil. This new optimization concept pioneered the remote (off-the-rig) downhole drilling-parameters surveillance in deepwater operations. Introduction A novel real-time optimization drilling service was implemented in 2008 with the major deepwater operator in Brazil in the Santos basin. Throughout the implementation and execution of the real-time optimization service, the importance of not only knowing where (wellbore placement) and what (formation evaluation) you are drilling but also how you are drilling, which is mainly driven by the integration between operator and service company, became apparent. After 3 years, it was clearly observed that the higher the integration between service company and operator was in a proactive and collaborative environment, the higher the drilling performance was. Today, in the deepwater Santos basin presalt environment, the real-time optimization drilling service is already part of the drilling program in almost every well, from the top hole section to the reservoir section. Real-Time Drilling-Optimization Team In 2008, to answer the “how” questions in the Santos basin, a new culture of real-time optimization arose with the concept of a multidisciplinary optimization team from the service company acting in collaboration with the major operator in Brazil in an integrated manner to achieve superior performance. To accomplish effective remote and rigsite real-time drilling optimization, it is important to use a highly specialized downhole drilling-dynamics MWD tool that records and transmits real-time dynamics data (e.g., stick/slip, lateral vibration, whirl, and axial vibration) and downhole drilling parameters (e.g., weight on bit, torque, revolutions per minute, and bending moment), which allows for a better judgment of the down-hole conditions while drilling and better support for adjusting the surface drilling parameters to optimize operations, in a continuous feedback cycle (Fig. 1).

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper OTC 22336, ’Case History: Performance of a Drilling Campaign in the Santos Basin, Brazil, 2008-2010: A Success Story,’ by Humberto Carrizo, Giovanny Ortuno, and Tarcilio Dutra Neto, Repsol Sinopec Brasil S.A., prepared for the 2011 Offshore Technology Conference Brazil, Rio de Janeiro, 4-6 October. The paper has not been peer reviewed. The evolution in well design and continuous-improvement actions are reported for the execution of five shallow-water and deepwater wells drilled by Repsol using a third-generation semisubmersible rig during 2008–2010. As part of the continuous-improvement approach, the quality-assessment/quality-control (QA/QC) procedures were tightened throughout the campaign. The proper use of after-action reviews at the completion of each well phase was paramount for the lessons learned from each well and their application to subsequent wells. Introduction The exploration-drilling campaign during 2008–2010 in the Santos basin used a moored semisubmersible drilling rig and was the first campaign in Brazilian waters by Repsol Sinopec Brasil. The blocks where these operations were performed are approximately 180 naut miles from the shore base. These wells were post-salt prospects in shallow and deep waters. The map in Fig. 1 shows the well locations for Wells A, B, C, D, and E. In the lower right of the figure is the order in which they were drilled, together with the respective water depth. The complete paper details well design and well operations from spud to total depth (TD). Actions considered key for performance achievements are framed by a continuous-improvement process, with tangible actions to reduce total time on well, and can be summarized as in Fig. 2. The total time on well can be reduced within the two stages of the well-construction process. During well planning: Make well-design improvements and/or plan application of a new technology. During project execution: Make well-operation improvements to remove invisible lost time (ILT) and reduce non-productive time (NPT). Well Planning Well-design activities carried out by the multidisciplinary project team are governed by the company’s well-construction process (WCP). The WCP is a gated four-phase process: visualization, conceptualization, definition, and execution. At the end of each phase, a gate-event meeting occurs in which a multidisciplinary technical team, based at headquarters, appraises information from the phase and then, depending on the results, decides whether to continue to the next phase. The WCP receives well data from the geological and geophysical team, and these data are essential input for well-design activities until the well design is fixed at the second gate and the basis of design is delivered. Design activities end with the drill-well-on-paper document. At the third gate, the drilling program is signed as the main deliverable before starting well operations.

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper OTC 19886, ’Presalt Santos Basin - Extended Well Test and Production Pilot in the Tupi Area: The Planning Phase,’ by Celia M.F. Nakano, Antonio C.C. Pinto, SPE, Jose L. Marcusso, and Kazuioshi Minami, SPE, Petrobras, prepared for the 2009 Offshore Technology Conference, Houston, 4-7 May. Petrobras is assessing the potential of the Santos basin presalt reservoirs offshore Brazil. Three integrated ultrafast-track projects were planned to start production of the giant presalt reservoirs in an area known as Tupi. The objective of the three projects is to obtain relevant reservoir and production data to support the design phase of the remaining production units of the full-field development. The main technical challenges addressed include drilling complex wells, use of intelligent completions, qualifying ultradeepwater risers, establishing flow assurance through long subsea flowlines, and CO 2 capture and sequestration. Introduction The Tupi area is in the central portion of the Santos basin, approximately 290 km offshore Rio de Janeiro State, at water depths of approximately 2200 m. The first well drilled in the block was Well RJS-628, completed in August 2006. The well was designed to test the carbonate section of an Aptian reservoir. It found a primary hydrocarbon-bearing reservoir in carbonate having microbial origin, named the SAG reservoir. A secondary microbialite reservoir, named the RIFT reservoir, also was found. Both reservoirs are below a thick regional layer of salt that occurs in this portion of the basin. Therefore, these reservoirs were classified as presalt reservoirs. The well was tested and produced after an acid stimulation. The choke-constrained production rates were 378 m 3 /d of 28°API crude oil with a gas/oil ratio (GOR) of approximately 220 m 3 /m 3 . To verify the continuity of the SAG reservoir to the south, Extension Well 3-RJS-646 was drilled in July 2007, 10 km from the wildcat. The well, in the Tupi Sul area, confirmed expectations of the SAG and RIFT carbonate oil reservoirs, and reservoir characteristics were better than those of the previous well. Another oil-bearing carbonate reservoir, the Coquina reservoir, also was found. The well tested a choked rate of 445 m 3 /d of 27°API oil from the SAG reservoir with a GOR of 230 m 3 /m 3 . Because of logistics constraints, the deeper reservoirs could not be tested. The reservoir area was covered completely by 3D-seismic data. High-resolution seismic is being acquired in the Tupi area.

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 17459, "Drilling Underbalanced From a Floating Unit in a 1,500-m of Water Depth Exploratory Well: Planning, Equipment and Rig Modifications," by A.C.V.M. Lage, E.F. Nogueira, G.S. Vanni, L.H.S. Vitullo, and and E.T.M. Fartes, Petrobras, prepared for the 2005 Offshore Technology Conference, Houston, 2–5 May. The full-length paper describes steps taken to drill the final section of an exploratory well in 1500 m of water in the Santos basin. The first well in the area reached a fractured carbonate reservoir where massive circulation losses caused the well to be abandoned. The full-length paper discusses planning activities, additional equipment, riser modifications, and drilling procedures for a new well to be drilled underbalanced from a drillship to access the target reservoir. Background Despite its use for many years, under-balanced drilling (UBD) is challenging to implement from floating units. Although thousands of wells worldwide have been drilled underbalanced, UBD is used almost exclusively onshore. The literature reports some UBD from fixed platforms or jackup rigs, but operational difficulties associated with safety, logistics, and equipment have limited UBD from floating rigs. At the end of 2000, Petrobras, along with other operators, drilled a well with aerated mud in the Albacore field in 974 ft of water from a semisubmersible, the Petrobras 17. Although not underbalanced, a two-phase mixture composed of nitrogen and water-based mud (WBM) was pumped down the drillstring and returned to surface under pressure. Returns were taken to a typical UBD surface system. After this milestone, Petrobras began development of technology for dual-gradient drilling (DGD). In DGD, gas is used to dilute the mud returns from the seafloor. From the point of gas injection to the surface, the drilling-fluid density is less than the effective mud density below the seafloor. In ultradeep water, DGD provides an effective approach to manage challenges associated with the narrow operational margin between pore pressure and formation fracture pressure. Fig. 1 shows the effective-circulating-density (ECD) vs. true-vertical-depth (TVD) profile for dual- and single-gradient drilling. Despite the advantages of DGD, most equipment currently available on floating rigs has not been designed to handle the returning liquid and gas flow. Drilling Experience. First Well. In 2003, an offshore exploratory well, targeting a carbon-ate reservoir, was drilled vertically in the Santos basin. The well was a slender design using 36-in. followed by 13 3/8-in. casing. After cementing the 13 3/8-in. casing, the 12 1/4-in. hole section was drilled, and the 9 5/8-in. casing was set at 4940 m, just above the zone of interest. The final section was to be drilled with 8 1/2-in. bits through the carbonate rocks from 4940 to almost 5900 m. A kick occurred while drilling the upper part of the carbonates. After controlling the well and increasing mud weight, the drilling operation resumed until the lower part of the carbonates was reached. The well had to be abandoned because of severe lost circulation.