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This paper presents the state of the art in frac packing learned from more than a hundred operations performed in the Campos Basin, offshore Brazil. Many reservoirs in the Campos Basin are clean tertiary age sandstones, very unconsolidated, with high to ultrahigh permeability. In this scenario, in order to get low skin completions, high conductivity fractures must be created. These can only be obtained with the use of aggressive tip screen out (TSO) techniques. For these reasons, no questions remain about the superiority of frac pack when compared with conventional gravel pack. Since February 1996, when the first frac pack job was performed, many challenges have been overcome, especially those related to handling leak off in very high permeability and the correct use of rock mechanics properties for proper frac pack design. These include minifrac analysis for very low efficiency fracturing fluids, the use or not of spurt loss, how fracturing fluid efficiency is affected by prior calibration tests, horizontal stress anisotropy for unconsolidated sands, stress contrast for layered sandstone's, etc. Others lessons have been learned such as: the need for high quality fluid, high quality proppant, good proppant placement, as well as calibration tests, real time design and BHTP data collection for all jobs (from electronic gauges or from live annulus). Introduction Sand control is mandatory. This is a law in high-permeability and soft formation scenarios. In the Campos Basin this is the case. Several oil and gas reservoirs in the Campos Basin are clean, high-permeability, tertiary age and unconsolidated sandstones located at water depths ranging from 100 ft (33 m) to 6070 ft (1850 m). Up to 1996, the usual completion method for sand control was the conventional gravel pack. The usual results, very closed to the worldwide mean1, were disappointingly high skins, even using best completion practices. The first Campos Basin frac pack completion was installed at the beginning of 1996. In 1997, frac pack completions became the usual sand control method, following the development of an in-house tool and the commissioning of a new stimulation vessel, able to pump aggressive sand schedules. The first results2 showed that frac pack completions resulted in much lower skin completions, in agreement with worldwide experience. In addition, it was observed that a bad frac pack job was always better or, at least, as good as a good gravel pack in the Campos Basin soft formations. Changing from gravel pack completions to frac pack completions brought new questions and doubts, that can be roughly divided into three groups. The first is whether frac pack operations needed to follow the strict procedures applied for gravel packs, such as, high density underbalanced perforating, pickling string, cleaning risers and casing, pre-job acidizing, proppant granulometry, etc. Second, due to ultra-high permeability's, design and pumping questions were imposed: What must be the conductivity of a fracture in formations with such high permeability's, ranging from 200 mD to 10,000 mD? How to obtain such a fracture? Can available commercial simulators be used to design this kind of fracture, considering that they were developed for lower permeability treatments? Is surface pressure data accurate enough to analyze calibration tests? Is the live annulus pressure precise enough? Can it be used for calibration test analysis and to make corrective actions during the main treatment? Can a very aggressive proppant ramp be pumped or even mixed? Third, due to the complete unconsolidation of the sandstones, it is almost impossible to obtain useful cores. Rock properties, then, cannot be obtained from laboratory tests. So, how can we obtain reasonable values of the stress contrast between the reservoir rock and the constraining formations? Are these constraining formations hard enough to contain the fracture? Frac pack is a completion technique that came from merging two distinct techniques: hydraulic fracturing and gravel pack completions.

The "Shale Gas Revolution" in North America has created both an opportunity and a challenge for the North Africa region for finding such unconventional resources. Approaches to finding them must be based on technology and planning to avoid unwanted expenses and error. Unconventional resources, for the purpose of this paper, are defined as tight and/or shale gas resources, although in North Africa, many of the challenges and potential solutions are equally applicable to oil rich resources. Key challenges specific to the North Africa region include the following: The availability of gas in North America has shifted LNG shipments to Europe (which is North Africa's biggest export market). The potential spread of this "revolution" to Europe could further erode the region's market share. The region faces a lack of infrastructure and a higher cost base for developing unconventional resources. As a result, little margin for error exists, nor can you afford to "learn by the drill bit." Therefore, you need to apply technology to reduce costs and increase well productivity and you need to develop a methodology that ensures minimal iterations. The latter requires a fully integrated approach to project evaluation, planning, and execution. As the highest portion of costs associated with developing shale/tight gas resources is for hydraulic stimulation (fracturing), this paper will focus on the best way to integrate: Reservoir characteristics (rock and fluid properties) Geomechanics Fracturing techniques A synergy of reservoir consultancy and pumping services has developed a close rapport and integrated approach that could be used by resource holders. This methodology can be modified to fit the requirements of NOCs or IOCs. This paper aims to highlight these and also offer a potential approach and methodology to evaluate these unconventional resources and secondly to apply technology to unlock their potential. Case studies will be used to demonstrate the pitfalls and challenges faced by projects in North America.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractActual worldwide oil production averages some 75 million barrels per day and, while estimates vary, this is associated with the production of 300 -400 million barrels of water per day. These values of approximately 5 -6 barrels of water for every barrel of oil are quite conservative. In some areas around the world, fields remain on production when the ratio is as high as 50 to 1.Water production causes several problems to oil wells such as scaling, fines migration or sandface failure, corrosion of tubular, and kills wells by hydrostatic loading, amongst other things. Thus, while water production is an inevitable consequence of oil production, it is usually desirable to defer its onset, or its rise, for as long as possible.Numerous strategies, both mechanical and chemical, have been employed over the years in attempts to achieve this. Simple shut-off techniques using cement, mechanical plugs and cross-linked gels have been widely used. Exotic materials such as DPR (disproportionate permeability reducers) and the new generation of relative permeability modifiers (RPM) have been applied in matrix treatments with varying degrees of success. Most recently, Conformance Fracturing operations have increased substantially in mature fields as the synergistic effect obtained by adding a RPM to a fracturing fluid have produced increased oil production with reduced water cut in one step, consequently eliminating the cost of additional water shut off treatment later on.This paper is an evaluation of various RPM materials commonly used on Conformance Fracturing treatments performed in the northeast of Brazil and other South American countries, rather than the usual laboratory testing methods and theoretical estimations. The paper also describes the technical design and operational methodology to treat single zone to laminated reservoirs with different mobility ratios. We believe conformance fracture techniques could significantly impact the development strategies of many fields worldwide.

Many of the mature oil fields in the world produce commingled water. Water production increases the lift cost of a barrel of oil, as it needs surface handling when it is to be disposed, re-injected into other wells, or used for a different purpose. Several techniques and chemistries have evolved over the past decades to address reduction of unwanted produced water. These different approaches to minimize water production are grouped under the name of water conformance. Selecting the proper water conformance method for a well depends on the correct understanding of the reservoir. Economics remains the main decision driver as to which technique and chemistry to use. A quite effective technique among the different water conformance methods is conformance fracturing, a combination of hydraulic fracturing and water control. Among several operating companies, hydraulic fracturing still is the preferred technology to increase well productivity. The development of a family of lightweight proppants for hydraulic fracturing has allowed a more uniform fracture height and width, due to a lesser degree of proppant settling inside the fracture, resulting in a better connectivity with the wellbore and lower chance of breaching nearby water zones. On the other hand, chemistry of relative permeability modifiers (RPM) has been greatly improved over the past decade, and one can observe longer life on water control treatments done using RPMs. In Brazil, we have conducted over 100 conformance fracturing operations to date, using conventional as well as lightweight proppants, and relative permeability modifiers, to meet the different targets they were deployed for. This paper will summarize these treatments (design, logistics, materials, equipment), with obtained results (oil and water production over time), showing the improvements made over time.