Petrobras pre-salt discovery is a huge hydrocarbon reserve located below an extensive layer of salt at about 5000 m depth. So far, the wells drilled at this scenario found light oil in highly heterogeneous carbonates reservoirs. The formation permeability varies more than four orders of magnitude. Some fields have most of the permeable zone with values ranging from 1 to 10 mD and this scenario requires stimulation in order to maximize productivity. This article will present the first multi-fractured sub-horizontal well constructed in the pre-salt reservoir. In this stimulation operation 8 acid fractures were created in a sub-horizontal open hole well. This article will show the completion selected that permitted to register the bottomhole data above and below the zone where the fracture was being created. This record allowed the interpretation if the fractures were really created in the zones selected or if there were communication between zones. The article will present the calibration tests results, the fracturing data of all intervals and some insights regarding fracture orientation due to temperature behavior. The reservoir depth and the proximity of the salt layer bring many challenges regarding hydraulic fracturing operations. This operation and other field results have shown minimum in situ stresses in the magnitude of 0.7 psi/ft and fracture propagation pressure that exceeds the estimated overburden. The records of the bottomhole pressure during this operation showed that there were some communication between zones. After the stimulation operation, a formation test was done measuring the well productivity and collecting samples of the reservoir fluid. The samples collected were analyzed and the tracers used during the stimulation were identified, indicating which fracture was contributing to production. The data registered during this operation is a huge lesson learned about doing multi-acid fractures in a carbonate reservoir for all the industry.

Pre-salt heterogeneous carbonate reservoirs typically present long net pays, high production/injection rates and some flow assurance risks. This paper presents general information, results and lessons learned regarding the installation of Intelligent Well Completion (IWC) in Santos Basin Pre-Salt Cluster (SBPSC) wells. It also presents some important improvements to be introduced in the future IWC systems specification and qualification based on the lessons learnt in these projects, setting some new challenges to the industry. The benefits expected with the use of IWC are achieved at the expense of challenging well engineering, since well completion design becomes more complex and well construction risks increase. Detailed and integrated planning is essential for the success of the operations, starting at the earliest phases of the well design and continued through detailed execution plans. The use of standardized practices and procedures has led to significant increases on installation performance. On the other hand, an open mind and a constant search for improvements allowed new solutions and procedures to be developed throughout the years. Regarding the system integration, a flexible and standardized control architecture was developed to allow combining different IWC providers and subsea vendors, which proved to be a successful approach. The most important improvement in IWC installation was the anticipation of the acid stimulation, nowadays performed before the vertical Wet Christmas Tree (WCT) installation. In order to achieve this goal some crucial improvements were gradually implemented in the stimulation practices, such as, an initial injectivity increase solution and some new acid diversion solutions, which allowed eliminating the use of coiled tubing and, as a consequence, the need of a subsea test tree. The well design team conducted an integrated risk assessment to properly evaluate the new practices and establish some actions to reduce the risks. Intense communication between production zones was observed during the acid job in some of the initial wells, ruining the gains of the IWC. After a comprehensive analysis, some possible causes were identified and with the new stimulation practices this issue was eliminated. Over the years, with the introduction of several improvements, some of them presented in this paper, the well completion duration was reduced to less than 50% of the one observed in the initial wells. This major performance increase has been essential to keep this deepwater projects feasible, especially in the oil scenario seen in recent years. Some of the new practices and lessons learned in this 100 wells equipped with IWC has set groundbreaking practices for Brazilian pre-salt fields development and may stand as a reference for the industry in similar deepwater projects. Additional requirements for future systems are expected to improve even further the performance in this scenario.

A potential problem when fracturing gas wells in deepwaters is the risk of hydrate formation during the flow for cleaning the well. Some alternatives have been used, such as the pumping of alcohol (methanol or ethanol) in the WCT (wet christmas tree) down the chemical lines or the postponement of the cleaning for some months, counting on the gravitational segregation of the fluids in the reservoir. In some cases, these solutions are not enough. In these cases, a possible solution is the combination of a saturated fracturing fluid together with a saturated brine, what reduces the hydrate formation envelope. This solution can be used in conjunction with other providences, such as the use of alcohol or glycol, sub-surface chokes, etc The present work describes the steps for the development of a fracturing fluid based on saturated brines and the planning, execution and evaluation of fracturing jobs performed in gas wells located in water depths that ranges from 840m to 1950m. Introduction Deep water operations are extremely expensive. Normally rig costs, together with the production unity construction, are responsible for the major part of expenditures in the development of an oilfield. Because of this, minimize non productive time is always an important part of the oilfield developing strategy. Coping with hydrates problems can be extremely time consuming and, in most situations, extremely risky. Normally, melting hydrates in pipelines, risers or wet christmas trees involves the use of heat (through the use of steam, hot water or thermochemical reactions - Marques, 2003), pressure bleed off or the use of chemicals. When pressure bleed off is applied to just one side of the hydrate plug, it can be extremely dangerous, because it can create a huge differential pressure across the hydrate plug making it behave as a missile. Besides that, melting the hydrate can generate a volume of gas up to 170 times the original volume, making this procedure still more risky. The use of chemicals can be ineffective or even impossible, due to the need of contact between the inhibitor and the hydrate plug. All of these solutions are time consuming, what means expensive. In view of these complications, the cliché "To prevent is better than to remedy" is tailor made when dealing with hydrates. In order to prevent hydrate formation a great number of procedures and inhibitors have been successfully developed. Very recently, inhibitors for fracturing fluids had been introduced in oil industry, since cleaning a gas well after a fracturing job has a great potential to hydrate formation. Since the production of gas from fractured wells deepwaters is quite new in Campos Basin, these products were not available when 2 wells were fractured. Because of this, an in house solution had to be implemented, by using a fracturing gel prepared with saturated brines. The steps of this development will be detailed below. Concepts Review Hydrates Hydrates are crystalline solids, with external aspect very similar to ice, which are formed when a specific number of molecules of water create cavities around gas molecules, at specific conditions of pressure and temperature. An example of hydrates can be seen in Figure 1 (a-d), which shows a hydrate deposition over a tree-cap located at 863 m of water depth.

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.

The use of the alpha and beta wave technique for a successful Horizontal Open Hole Gravel Pack is based upon a well without, or with minimum, losses. In this case, the gravel particles will be adequately carried to the expected point of deposition. So, in case of any mud losses, both while drilling the reservoir or during pre-completion operations, an efficient loss control method should be used, in order to allow the best packing of the screen with gravel particles. Besides a brief revision of current techniques, this paper details a well succeeded loss control strengthening operation, when water based drilling fluid was injected during the pre-completion operations of a production well with long horizontal section in Campos Basin. After the displacement of the water base drilling fluid 9,4 ppg by completion fluid (brine) 9,4 ppg, the well started to lose about 15 bph of fluid. Based upon solid previous experience, an acceptable limit for WBM losses is about 2 bph. The well was reconditioned with WBM, lowering the losses for 5 bph, still too high. So a LCM pill was injected into the formation, above fracture pressure, using the "sealing fracture method". This procedure resulted in a well without any losses, which allowed the displacement by brine, the running of premium screens and complete the pumping of HOHGP without any incidents. Introduction The need for high productivities and for the optimization of the rig time made the horizontal wells the pattern for drainage of Campos' Basin deep water reservoirs. The solid experience of 260 wells equipped with HOHGP, with more than 550000 feet of screens run in, without a single failure in contolling sand production, confirms the success of this choice. This success is the result of the great evolution of procedures that incorporated the lessons learned since the first horizontal gravel packed well built in 1998. The most important of these learned lessons is the perfect understanding of the process of alpha-beta waves for deposition of the gravel pack and its requirements, such as: a well without losses, a thin mud cake (without fluff) and with appropriate gravel granulometry, the knowledge of the operational limits imposed by the geo-mechanics conditions, etc. As the demanded high productivity depends a lot of a thin non-damaging mudcake and HOHGP depends on a well without any losses, a narrow operational window is left by pre-completions operations. Therefore, to understand both the wellbore losses and leak off importance in the gravel pack process is a key of the HOHGP success. By this way, managing losses become a natural part of the process. Some Basic Concepts Alpha-Beta Wave Fundamentals The alpha-beta wave technique is based upon the return rate. Although simulations (see graphs below) and technical descriptions normally refer to pumping rate or entrance velocity, what really matters is the output velocity, that means return rate.