Traditionally, Non-Aqueous Fluids (NAF) have been used by a major operator to drill challenging wells in the Campos Basin, Brazil. Significant advances in water based drilling fluid design in the recent years have allowed water-based drilling fluid performance to approach that of NAF. Exploration in the new frontiers and optimized development well projects in deepwater Brazil have required a different approach regarding drilling fluid design due long step outs, difficult well trajectory, and the possibility of drilling horizontal wells in one step, thus avoiding intermediate casing strings. Although NAF are an ideal candidate for those applications, environmental concerns and logistic demands are still an issue and alternatives should be considered. HPWBM has been applied to replace NAF in some applications in deepwater and ultra deepwater (UDW) in the Campos Basin. This novel technology has been successfully applied to drill in UDW scenarios, reactive clays, dispersive shale, naturally micro fractured formation and horizontal wells. HPWBM characteristics are developed with:A new generation of encapsulation polymers;The use of amine chemistry to provide clay stability;The application of novel sealing polymer for shale stability; andExcellent mud lubricity characteristics. The lessons learned, as supported by case histories and lab data have contributed to system modifications which have improved performance. This work has also identified attributes needed to complete a drilling fluid design for the difficult wells to be drilled in the new exploration and development areas. The evolution of HPWBM drilling fluid design will be discussed along with how decisions were made. Introduction Today the industry is drilling more technically challenging wells difficult wells. Exploration and development operations have expanded globally as the economics of exploration and production for oil and gas have improved with advancements in drilling technology. Advanced drilling operations such as deep shelf, extended reach, horizontal and deepwater are technically challenging, inherently risky and expensive. With consideration to reducing drilling problems such as torque and drag, stuck pipe, low rate of penetration and well bore stability; these wells are generally drilled with emulsion-based muds. Nearly three quarters of the earth is ocean and a high prospect of hydrocarbon resources in addition to the other marine resources. That's why the industry is shifting from onshore drilling to offshore drilling. Published information indicates the presence of more than 20% of world's proven reserve in offshore geological structures. According to future production forecast of production reserves about 40–50% of future hydrocarbon recovery will be from offshore reserves. This is reflected by the increasing activity in the offshore environment with a gradual shift from shallow water drilling to deepwater drilling operations. This scenario is particularly critical in the drilling exploration of offshore Brazil where the country faces the challenge of increasing oil production and reaching energy self-sufficiency within the next few years. Petrobras is well known for extended deepwater experience, however exploration in the new frontiers of ultra deep water face new challenges.

It is estimated that there are large reserves of unconventional gas located throughout the world, including coalbed methane, shale gas and tight gas sands. Due to their specific characteristics—particularly low permeability in the microdarcy range, microfractures and high capillary pressures—unconventional gas reservoirs are vulnerable to irreversible damage during ex-ploitation. This paper focuses on studies of damage evaluation in unconventional gas reservoirs around the world. We aim to provide a set of guidelines to avoid, minimize and/or remediate this damage. In Brazil, the Petrobras Strategic Plan for 2020 predicts 200% growth in gas production until 2020, as compared to 2010 gas production. Expected growth in international gas production will be 30% until 2020, as compared to 2010 world gas pro-duction. The main natural gas production projects of Petrobras between 2010 and 2014 are Mexilhão, Uruguá and Tambaú Cidade de Santos, totaling 35,000 BOE per day. Demand for natural gas is expected to increase from 46 million m3/day (2009) to 130 million m3/day until 2014, envisaging use in electrical power, industrial, fertilizer and other applications. The fundamental processes causing formation damage include but are not limited to physicochemical, chemical, hydro-dynamic, mechanical, thermal and biological. Formation damage is not necessarily reversible, and therefore it should be avoided. Laboratory tests are designed to determine, understand and quantify the governing processes, their dependency on the in-situ and operational conditions, and their effect on formation damage. It should be emphasized that on one hand, high capillary pressure favors the spontaneous imbibition phenomenon and, consequently, mainly water-blocking damage. On the other hand this same effect has been investigated by several researchers to change the reservoir wettability by optimizing rock-fluid interactions using specific surfactant-brine systems during exploi-tation. It has been concluded that, beyond formation evaluation, phenomenological observations and the optimization of rock-fluid interactions are likely to promote gas production from minimally damaged unconventional reservoirs. Introduction Reservoirs that originally contain free gas as the only hydrocarbon source are termed gas reservoirs. These reservoirs store a mixture of hydrocarbon compounds that exist entirely in the gaseous state. The gas may be ‘dry,’ ‘wet,’ or ‘condensate,’ depending on its composition, as well as the pressure and temperature at which the accumulation occured1. A natural-gas source is named an unconventional gas reservoir when the well must be stimulated by large hydraulic fracture treatment, ho-rizontal wellbores or multilateral wellbores to produce at economic flow rates or volumes2. Similar to conventional hydrocarbon sources, unconventional gas reservoirs present complex geological characteristics, as well as heterogeneities at all scales. Unconventional gas reservoirs, though, typically have very fine-grain rock size distribu-tion, gas storage and flow regimes influenced by the tight pore throat. Grain rock size distribution and organic and clay con-tent can promote favorable bonds between the gas molecules and the rock surface3. The three major categories of unconven-tional gas reservoirs are coalbed methane, tight gas sands and shale gas2. In terms of pore structure, shale gas reservoirs typically present dimensions at the nanometer to micrometer size, while tight gas sands present pores in the micrometer or larger size3. Coalbed methane systems are naturally fractured and can present two distinct porosity patterns: one primary composed of micropores with extremely low permeability; and one sec-ondary composed of macropores with a natural fracture network of cracks and fissures1. One important aspect to consider for unconventional gas reservoirs due to their lower permeability in contrast to high permeability reservoirs, is that the effects of capillary pressure are significant4,5. All these characteristics make unconventional gas reservoirs more susceptible to damage during exploratory phases and processes6.

This article details the planning and execution phases of the first open hole gravel pack operation performed with the alpha beta wave deposition technique using a non aqueous system as a carrier fluid. The operation was performed at Marlim Field, offshore Brazil, and constitutes the first field implementation of a research and engineering effort which started two years ago. The idea in this first field operation was to avoid many changes in the original well design for the area and to concentrate novel steps in the fluid for gravel packing openhole design, friction loss evaluation, fluid substitution and rheology characterization are some of the new aspects detailed for the fluid design. Based on these results, optimized procedures were proposed for the operation. A broad description of the technical aspects, field pumping profiles and packing quality is also presented. Introduction Most of the large production wells in sandstone reservoirs require sand control due to the poorly consolidated formations. Open hole gravel pack (OHGP) is still the most popular solution for sand control in offshore deepwater reservoirs. The petroleum industry has developed a number of fluid systems for a successful OHGP: including a water-based drill-in fluid (DIF) and gravel carrier fluid, (widely applied in Brazil, Marques et al.1, Farias et al.2) or using a synthetic DIF and water based gravel carrier fluid 3. In spite of the industry's effort to develop high performance water-based fluids 4,5, the use of synthetic fluids guarantees superior wellbore stability, lubricity, inhibition and drilling performance. Substituting synthetic DIF for water-based gravel carrier fluids is a complex operation, due to the potential for fluid interaction, formation damage and problems of offshore logistics. Another challenge is to provide a reliable sand control technique in the horizontal section with operational safety and minimum formation damage. Parlar et al.6 presented field implementations of OHGP operations considering high viscosity non-aqueous fluid (NAF) and alternate path concepts. The field job herein detailed is the first field implementation of a corporate program within Petrobras which focused on developing technology for performing OHGP with NAF systems, considering alpha and beta-wave deposition. This gravel pack placement strategy is considered to be reliable, cost effective and widely validated within PETROBRAS using brines as carrier fluids. The ability to run such operations with NAF systems allows aims the application in different scenarios, such as:"Infill drilling" projects, allowing for considering re-entries in existing vertical wells in mature fields. The strategy includes opening a 8 ½" window in the 9 5/8" casing, drilling build-up and reservoir sections in the same phase, enabling the use of conventional screens and sand control equipment.Reduction of time and costs in the execution of conventional horizontal wells by drilling build-up and reservoir sections in the same phase and performing OHGP with a compatible carrier fluid.Execution of horizontal wells with OHGP in reservoirs sensitive to aqueous fluids. Well Design The main objective of the well was to produce oil from the Marlim field's 230 and 250A sands at a 670m water depth. After launching the 30" torpedo casing, the pilot well was drilled to 1, 115m with a 26" rock bit and the 20" casing shoe was set at 1,100m. The BOP stack was run and tested, and the well was drilled to 1,862m. The 13 3/8" casing was then run to 1,848m. The pilot well was then drilled to 2,896m with a 12 1/4" PDC bit, using non aqueous DIF from 0 to 53 degrees.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThis paper deals with the adaptation of synthetic drilling fluid for use in milling operations in offshore wells. Main topics covered include: a discussion on the fundamentals of solids transport highlighting the critical aspects of transporting iron particles in offshore wells; a computer simulation task, based on solids transport mechanistic models, to define minimum requirements for fluid flow rates and rheological properties; an extensive experimental work comparing the carrying capacity of water and synthetic based fluids and; the process of field implementation concentrating on well succeeded experiences in the offshore fields operated by PETROBRAS.

This article details the planning and execution phases of the first openhole gravel-pack (OHGP) operation performed with the alpha-/beta-wave deposition technique using a nonaqueous system as a carrier fluid. The operation was performed at Marlim field, offshore Brazil, and constitutes the first field implementation of a research and engineering effort that started two years ago.The idea in this first field operation was to avoid many changes in the original well design for the area and to concentrate novel steps in the fluid for gravel packing openhole design, friction loss evaluation, fluid substitution, and rheology characterization. On the basis of these results, optimized procedures were proposed for the operation. A broad description of the technical aspects, field pumping profiles, and packing quality is also presented.