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 northeastern region of Brazil is the largest onshore oil producer in the country. However, regional oil production is still much less than offshore production in other Brazilian basins. Therefore, customized low-cost technologies are routinely employed locally to deal with issues, such as perforation plugging, scaling, and sediments production, for example. Heavy oil produced in this area builds up paraffin and asphaltene deposits over time, further decreasing productivity of the fields. This paper discusses applying a true fluidic oscillator (TFO), an enhanced rocker tool (ERT) that synergistically combines fluidic, acoustic, and chemical effects, to enhance the action of a fluid treatment on the formation. Usually, this tool is used in conjunction with coiled tubing (CT) equipment. Because the operator considered a CT operation too expensive for the needs of this region, the tool was run into the well with a regular work string as a lower-cost alternative. Three similar wells in the Potiguar Basin were selected and treated with diesel and butyl glycol through the TFO with significant improvement in estimated permeability and oil production (an increase of 20% to 240%) after treatment. Overall, the tool enhanced the treatment effectiveness by amplifying the contact area between fluids and formation. This demonstrated the applicability of this cost-effective solution for stimulation of low-productivity wells.

This paper presents the results of remote acidizing treatments performed in 7 injection wells of the Marlim Field, which is responsible for 35% of the Brazilian oil production. In recent years, solids and rust from the seawater injection process have severely reduced the injectivity of the wells. However, the high costs involved and the limited availability of dynamically positioned rigs required for conventional treatments have prevented the restoration of the injectivities and, consequently, the production of adjacent wells had to be restricted. The advent of remote operations using stimulation boats anchored to production platforms, whose application on a production well was described on a previous paper1, provided a simple, efficient, and economical solution to the problem, since all treatments were operationally and economically successful, resulting in a total increase in the water injection rate of 6613 m3/d. In addition, the paper presents laboratory experiments that have been conducted to verify the influence of the acids (HF and HCl) upon the flexible flowline, wellhead equipment and the string's metals, which have shown that pumping acid remotely was safe. The technique developed can be applied to other deepwater offshore fields and ongoing research is being performed in other to extend it to different situations, such as production and/or gravel packed wells, where acid diversion plays a major role in the operation's success and spent acid may cause even more severe corrosion problems. Introduction The technique of remote acidizing was created because of the need for treating seawater injection wells of the Marlim Field, at the Campos Basin, offshore Brazil, and the limited availability of dynamically positioned intervention rigs to perform these treatments in a conventional way. Marlim Field produces almost 35% of the Brazilian production and almost 60% of all the oil extracted daily from the Campos Basin. For not having an active aquifer or gas cap, oil production relies strongly upon seawater injection for pressure maintenance. In 1999, it was verified that the average injectivity of Marlim's wells had dropped to 30% of its initial value, what caused an alarming injection deficit, with the injection pressures reaching the operational limits. In order to restore injectivity, acid treatments should be performed. However, to acidize deepwater satellite wells, it would be necessary to use dynamically positioned vessels (DPV) for the intervention, but the costly operation and limited availability of those rigs prevented the execution of these treatments.