The paper describes the actions taken to re-entry a well located in ultra-deep waters (1541 m water depth) whose sub sea Christmas-tree was blocked by a solid hydrate plug and therefore could not be liberated by means of its standard releasing tools.A heat-releasing treating fluid -the so-called self-generated nitrogen (SGN) fluid -was successfully applied to heat and dissociate the hydrate plug, which was totally blocking the locking mechanism of the Production Vertical Connection Mandrel (PVCM) of the tree. The heat applied around the Xmas-tree body was conveyed by the pumped SGN fluid batches. By doing so, the hydrate plug was completely dissociated (melted down) and then the unlatching mechanism became operational again. This paper comprehensively describes the steps of this different hydrate treatment job. In broad terms, a technically challenging job which encompassed the following issues: -development of a "tailor-made" environmental-friendly SGN formulation, -heat exchange simulations to design the optimum volume for the SGN treatment batch, -a review of the theoretical aspects of hydrate formation/dissociation, -use of an instrumented/insulated drill pipe riser (DPR), -and job safety procedure reviews. A PLT logging tool (PLT) was also used to keep a record of the temperature profile inside the DPR.In view of the pioneer aspects of the operation, the combined use of an ROV and PLT was of paramount importance to monitor every step of the operation since its very beginning. Along the job, the Christmas-tree, the reactivity of the treating fluid batches, the temperature changes, and the hydrate blockage, were monitored on a permanent basis. The combination of these two tools has provided precious pieces of information that have enabled us to gain insight into what was going on along the job and take the necessary measures to its real-time optimization.

This paper presents the lessons learned by Petrobras after performing a total of 124 horizontal open hole gravel-packing operations in Campos Basin. The authors intend to describe how the industry-provided standard gravel packing procedures had to be continuously improved and/or adapted to meet Campos basin requirements, such as: -low fracture gradients, - long intervals to be packed, -pumping jobs performed from floating rigs and -the need to sustain high production levels - or high injection rates - to justify the huge amount of investments associated to ultra-deepwater production enterprises. It is also described the main technology innovations that were incorporated to our completion projects in the last few years. Among these innovations one can find: - modified standard tools to reduce pumping pressures, - external casing packers, -inflatable straddle packer to divert post-gravel treatments, -pressure reducer valves, - - flowline's flow meter and shunt tubes. Formation damage in gravel packing operations is addressed on a comprehensive basis, encompassing the following items: -drill-in fluid rheological specifications, - pre-job wellbore cleanup procedures, - optimizing drill-in-fluids mud cake removal, -job design and execution, gravel carrier fluids filtration requirements, -postjob remedial treatments and diversion techniques as well. Introduction The most prolific reservoirs in Campos Basin are Tertiary and upper Cretaceous unconsolidated turbidites that require a sand control/exclusion method either to maximize sand-free production or to manage massive water injection to provide reservoir pressure maintenance. Therefore, from the firstdiscovered oifields in shallow waters to the large ones more recently discovered in deep- and ultra-deepwaters scenarios in Campos Basin, emphasis has been placed on total sand exclusion well completion techniques. Propelled by the ever-growing complexity of Campos Basin wells, as we moved from shallow to ultra-deepwaters, sand control technology innovations were incorporated to our projects on a continouos basis, such as:–cased-well frac pack, -chemical consolidation (one single case),–stand-alone completions (sintered metal mesh and premium screens),–highly-deviated- and horizontal-open-hole gravel packing and very recently expandable screens (ES). Currently, gravel pack is the most popular sand exclusion technique used in Campos Basin. From the early 1980's to circa 1995 this technique was applied to cased-wells only1. Nevertheless, huge production impairments were a common place due to non-optimized cased-hole gravel packing techniques. Typically, PI reductions of up to 75 % were recurrent at that time. A series of improvements to the existing cased-hole gravel packing placement techniques was subsequently made. As an outcome of such actions a fair reduction of the pressure drop across the gravel ended up being achieved. However, the magnitude of the productivity index (PI) of the gravel packed cased-wells, hovering around 8,8 bbl/psi, was still a short-coming for the economical feasibility of these shallow waters projects and for the deepand ultra-deepwaters ones as well. As an alternative completion technique to cased gravel packed wells, the frac-pack technique was introduced early in the 1990's in Campos Basin.2 The application of this technique to vertical- and deviated- cased-wells in Marlim field was a step further towards a better sand face completion.

The emergence at the end of the twentieth century of a mass organization of landless peasants demanding land reform can only be understood when viewed against Brazil's archaic land structure, where 1 percent of landowners own 46 percent of the land and government inspectors are still discovering slave labor on Amazon cattle ranches.

This paper presents the results of a fracpack campaign in a series of very high permeability gas wells in Espirito Santos Basin, off-shore Brazil. This first fracpack campaign in four wells was conducted from March 2007 to June 2008. Permeability ranges from high 50 mD to very high 200 mD. The main debate was internal: why does someone need to fracturing very high permeability gas wells? In fact, this question is associated to two issues: overcome formation damage and assure very reliable sand control. The answer is obvious: fracpack. Several injection tests and minifrac prior to the main treatment were performed in order to address mainly closure stress and fluid leakoff although perforation friction, near-wellbore tortuosity were minor concerns. The main drive was the amount of fluid required to effectively propagate a fracture in such very high permeability gas wells. Again, someone claimed the volumes would be enormous! However, it was observed that this volume was almost the same ordinary volume used in Campos Basin´s regular oil fracpacks. The results were outstanding. The production tests showed some of the greatest absolute open flows in Brazilian gas wells. All the wells are current in production and sustaining the very high productivity levels. Introduction The Peroá gas field, discovered in September, 1996 from 1-ESS-77 well, lies in 70 m water depth and is located around 52 km offshore near the mouth of Doce river - Fig. 1. The main Peroá reservoir is channelized Oligocene turbidites sandstones deposited in the base of escarpment toward diapirism salt channels. Petrophysics and log data point out good to very good porosity (17% to 24%) and gas permeability (50 mD to 200 mD), Sw from 15% to 36%. Original reservoir pressure is from 209 and 290 kgf/cm2, 2460 to 2700 m TVD.