Hydrate and paraffin blockages are the major causes of oil production losses in deepwater scenarios like the ones existing in Campos Basin area. This paper is aimed at describing two new applications of a thermochemical method (SGN method) which has been extensively used by Petrobras (in 200+ jobs) to unplug subsea flowlines by organic deposits, viz,- to dissociate a gas hydrate buildup in a subsea christmas-tree, - and to melt a massive wax deposit accumulated in a subsea flowline ahead of a stuck pig. Both successful jobs were performed in Campos Basin, offshore Rio de Janeiro. Hydrate formed in the pistons chamber of the christmastree- cap's locking-pins was the cause of the operational failure to re-entry a subsea well (The well's christmas-tree is at 601 m water depth). This paper describes in details the designed "tailor-made" solutions to work out the problem. It encompassed the following points: development of environmental-friendly SGN formulation, - heat-exchange simulations, mechanical modifications of the regular tree-cap releasing tool, job planning and safety procedures. Along a routine pigging job, excessive wax was allowed to accumulate ahead (downstream) of a foam pig in the flowline of a well. This well produces to an FPSO. So, the pig got stuck. Our attempts to release it by means of standard procedures were fruitless. Therefore, an innovative engineering solution had to be developed. A sonic method was used to pinpoint the wax blockage. It also entailed spotting the thermochemical SGN fluid - with the aid of a coiled tubing unit - to melt the wax blockage ahead of the pig. There were some drawbacks we had to face to perform this job. For instance, there is no room enough in the FPSO turret area to place a regular coiled tubing(CT) unit out there. So, mechanical modifications had to be carried out to attach the CT's injection head to the FPSO's turret and to safely operate the CT unit from outside the revolving turret area. The paper also describes the kind of approach engineered to release the pig on a step-by-step basis. To our best understanding both approaches used to work out the two described problems are sound technology innovations. They surely are unique flow assurance solutions for deepwater scenarios. Introduction Over the last quarter century Petrobras has concentrated most of its E&P activities in the prolific Campos Basin area, offshore Rio de Janeiro State (Figure 1). Nowadays, around 82 % of all Brazilian domestic crude output come from this province. Out of this total, production facilities located at deep (1,000+ ft water depth, 300 m) and ultra-deepwaters (4,921+ ft water depth, 1,500 m) contribute with circa 84 % of the total Basin production. It is well known that deepwater production environments bring with it additional challenges to assure maximum productivity of the wells. Figure 1 - Campos Basin location, offshore Rio de Janeiro state, Brazil.(AVAILABLE IN FULL PAPER)

The paper presents an overview of the evolution of Petrobras open hole gravel packing operational practices after the 200th well has been successfully completed with this technique in Campos Basin (CB): a milestone in the history of Petrobras completion practices in deep and ultra-deepwaters. The paper also presents a comprehensive description of the main steps taken to improve our horizontal open-hole gravel packing (HOHGP) practices towards a best-in-class status in unconsolidated oil-bearing turbidites. Since the first HOHGP job done in 1988 we had to move progressively from shallow to ultra-deepwater completion scenarios. Along this path a series of innovations has been incorporated to our sand face completion practices due to the ever-growing-complexity of the wells geometry, longer intervals to be completed, heavier oil reserves to be developed, rock mechanics restraints (ever-lowering fracture gradients) and the necessity of damage-free-, high-performance-wells to cope with the skyrocketing capital expenditures which is a general rule for offshore ultra-deepwaters nowadays. Petrobras strategy conceived to continuously enhance its HOHGP completion efficiency index encompasses, the following interrelated subjects: -a comprehensive long-term plan to deal with the problem, -a multi-disciplinary team-work approach, -a strong cooperation with gravel packing tools & screens suppliers, -improvement of operational procedures and guidelines against which to measure well performance and -research & investment in cutting-edge technologies. Discussions on the challenges envisioned for HOHGP operations in ultra-deepwaters in the years to come are also presented. Introduction The most prolific reservoirs in CB are the Upper Cretaceous and Tertiary turbidites. These high-permeability (circa 1000 – 8000 mD), stacked and amalgamated reservoirs are spread over in shallow, deep- and ultra-deepwaters within the Basin. Figure 1. Dictated by the depositional model associated to turbidites, the sand uniformity of these poorly- or un-consolidated sand lenses vary quite a bit. The presence of reactive shale streaks is recurrent in some of these turbidites. As a trend in many other offshore basins in the world, the first oil discoveries (early in the 1980´s) in turbidites were located in shallow waters of CB. These good exploratory results have propelled us to move progressively from shallow to ultra-deepwaters scenarios. However, since the pioneer oil discoveries we have realized that a sand management strategy was necessary to achieve the desirable levels of production. In fact, sand control is an umbrella term comprising different approaches to dealing with sand production problems. Different sand control methods are known: frac-pack, chemical consolidation of sand grains, use of screens: sintered mesh, conventional, expandable (ESS); use of slotted liners, gravel packing, inter alia. Petrobras philosophy is one of zero tolerance concerning sand production in offshore fields lest the governing parameters for sand production are not well established for the vast majority of actual field situations and they may change along the life-span of the wells. Should there be the slightest chance of sand production, a sand control method is installed in our wells. In essence, this preventive approach to sand exclusion stems from the following facts: wellbore integrity concerns, prohibitively high well intervention costs, the need to maximize production rates, to achieve a maximum completion efficiency index, safety concerns, payback economics, and incapability of sand-dealing in top-side equipments. In fact, our offshore production facilities have not been designed to process sand-bearing crude oils.

This paper focuses on the first global installation of a water injector well with a lower completion system that incorporates both premium sand control screens and water injection profile equalization. The equalization of the water injection profile of horizontal wells has been a key issue in many development projects worldwide and has the potential to increase the reservoirs ultimate recovery by increasing the water sweep efficiency. Inflow Control Devices integrated with premium sand control screens have a long history of application in production wells. In these cases the main objective is to create a uniform inflow profile along the horizontal section, delaying unwanted water and gas production and increasing oil recovery. The method through which Inflow Control Devices equalize the inflow of oil can also be used to equalize the outflow of water. Historically, sand control completions for water injection wells include stand-alone conventional screens and open-hole gravel packs. Stand-alone conventional screen completions do not provide equalization of the water injection profile. Open-hole gravel packs provide for an effective acid treatment of the water injector well but present operational risks, high costs, as well as expensive rig time. The installation was carried out in a subsea horizontal sea water injector well in the Campos Basin, offshore Brazil. The paper presents the overall completion plan, the lower completion installation, the acid treatment through the Inflow Control Devices, and the initial water injection results based on production logs and water injectivity tests. The main concerns during the planning phase are discussed, highlighting the procedures adopted to overcome them. The good initial results have created the expectation of many applications of this system in Campos Basin. It is believed that sharing this information will benefit many operators with horizontal water injectors in their field development plans. Marlim The Marlim field, located in the northeastern part of Campos Basin, about 110 km offshore in the state of Rio de Janeiro, was discovered in January 1985. The field covers an area of about 145 km2, in water depths ranging from 600 m (1968 ft) to 1,100 m (3609 ft). The Oligocene sandstone reservoir quality is good. Core analyses of several wells indicate mean permeability of 2,000 md, mean porosity of 30%, and highly friable sandstone. Marlim's reservoir development strategy relies heavily on water injection as a source of reservoir energy maintenance. Currently 9 Floating Production Systems (FPS) are on stream with 129 subsea wells on operation (83 producers and 46 water injectors), including 36 horizontal wells. The total production reached its peak of 650,000 bbl/d in 2002, overcoming all former production forecasts. Currently Marlim field oil production, around 450,000 bbl/d, is supported by injecting 760,000 bbl/d of sea water. The recovery factor to date is 22.9 %. The water production is 217,150 bbl/d (water cut of 33 %) and GOR is equal to the initial solubility ratio, 83 STD m3/STD m3. Water injection is into the oil leg, concentrated in the lower portions of the reservoir and production is concentrated in the upper parts, to delay water breakthrough. A thorough history of the Marlim field can found in references 1 through 6. Injection Well Strategy The water injector well under consideration for this project was to be located in the south area of the Marlim field. This injector well was planned for pressure maintenance and for sweep efficiency in the thin reservoir border of the field. The injector well, IN, and its neighboring producer wells, A, B, C, and D are shown in Figure 1.

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 Injection Above the Fracture Pressure (IAFP) has became one of the most important alternatives to guarantee high injection rates, even when the quality of the injected water is below the minimum requirements for not damaging the rock-reservoir. For this reason IAFP has found a vast application in both, the discard or re-injection of oily water or water with high solid content and to maintain the injectivity index of injector wells. In Campos Basin, an interesting application of IAFP to assure the injection rate has been done in a pair of parallel horizontal wells completed with HOHGP (horizontal open hole gravel pack) in a Maastrichtian reservoir, where the fracture growth has been monitored through Hall Plots. In the first group (IAFP for water discard) some new projects have been planned, such as an "ecological well" (so called because the reduction of discard) which plan to inject large amount of water in dolomites. All these projects were preceded by a fracture growth analysis. Usually, these analyses are carried-out by using simulators which are based in Linear Elastic Fracture Model theory (LEFM) and consider a single planar fracture. However, in the case of IAFP in non-consolidated sandstones or soft carbonates, these assumptions can be quite unrealistic. Effects of plastic deformation in the fracture tip, compacting or fluidization of porous media, multiple fractures and pore-elastic effects can be predominant in these cases. An example that ratifies this was the attempt to re-inject produced water above the fracture pressure in an unconsolidated Miocene reservoir. Even with injection pressure 800 psi above the fracturing pressure (measured through a previous minifrac), it was impossible to propagate the fracture. In another well, the IAFP was aborted when a completely unexpected fracture gradient greater than 0.83 psi/ft was attained (it was expected 0.52 psi/ft). This behavior can only be explained if we consider the occurrence of any different phenomena of those foreseen by LEFM. This work details the IAPF projects here mentioned and depicts the deviations of LEFM observed in IAFP wells in Campos' Basin. Introduction The analysis of Figure 1 confirms the cliché that "We work in a Water Industry. The oil is just a supporting actor". This data collected in 2006 reflects the historic and the forecasted production and water injection for all the projects on development at that time in Campos Basin. The actual data, which confirmed the forecast, shows that in 2009 the oil production is circa 2,000,000 bbl/day, while the produced water is circa 3,400,000 bbl/day. If we consider that this water is re-injected or properly discarded, the total amount of water handled per day is almost 7,000,000 bbl in Campos Basin. In broad terms: "Managing water is not part of our business. It is our business". And doing that efficiently means to increase oil production at lower cost. Water injection and produced water re-injection play an extremely important role in this process (Furtado, 2005). Basically, water injection is carried out to accomplish the following functions: sweep efficiency improvement, reservoir pressure maintenance and produced water discard.