Drilling operations in salt zones have gained importance in Brazil due to the discovery of large oil and gas reserves in the Pre-Salt area. Thus, the pursuit of excellence in such operations is requiring considerable development of new operational practices and technologies. Synthetic base mud has been the first choice to drill through evaporite sections in Pre-Salt zones. Synthetic fluids application practically eliminates salt dissolution and improves caliper quality. However, depending on the salt mobility rate, stuck bit and/or stuck pipe can happen, demanding the injection of fresh water pills for its liberation. In some wells, the frequent use of those pills resulted in enlarged sections. The situation gets worse in scenarios where loss of circulation is a major issue. On the other hand, the use of non-saturated aqueous fluids to drill soluble salts (e.g. halite, tachyhydrite and carnalite) can result in localized enlargements due to leaching process. Drilling a gauge hole is a very important issue to prevent wellbore collapse and/or problems in cementing operations. However, high operating costs associated to deep water drilling is placing additional emphasis on drilling performance in order to reduce the operational time, without losing the quality of the wells. This concern raises the issues of how to most effectively improve operational performance regarding the drilling fluid selection. The paper presents the results of the use of water based muds in the drilling of two offshore wells in Brazilian Pre-Salt area and highlights the lessons learned from the experience. Before the field application extensive lab tests and numerical simulations were carried out to support the drilling fluid design for the wells. In the first well, differences between the planned and encountered drilling conditions led to fluid replacement during the operation. On the other hand, in the second well, 2.000 m salt extension was successfully drilled to depth with no major operational problems and good drilling performance. The field application of WBM proved to be a good option to drill the salt layers in the development of Pre-Salt fields but it demands a more detailed knowledge of both lithology and stratigraphy of the evaporite section. Introduction The drilling fluid design for salt zones uses to focus on drilling a gauge hole to prevent wellbore collapse. Due to solubility issues, synthetic based emulsions have been selected as the first option to drill through evaporite layers in the Pre-Salt scenario. However, high operational costs associated to deep water drilling have brought special attention to drilling rates in order to reduce operational time without loss of well quality. In offshore drilling operations, the use of synthetic based drilling fluids demands the use of centrifuges to clean the cuttings before they are discharged into the sea. This procedure results in strict control of penetration rates due to cuttings processing issues. Moreover, in scenarios where lost circulation is a major issue the use of synthetic base muds may not be the best choice. Therefore, the challenge is to find the best way of effectively improving operational performance through an adequate drilling fluid selection. And it raises the question: should water base mud (WBM) or synthetic base mud (SBM) be used? In Brazilian Pre-Salt scenario, the most common salts encountered are halite (NaCl), carnalite (KCl. MgCl2.6H2O), tachyhydrite (CaCl2.2MgCl2.12H2O) and anhydrite (CaSO4). The deposition sequence normally is the opposite of the salt solubility in water which, for these salts, follows the same sequence of easiness of reaction with water: Tachyhydrite > Carnalite > Halite > Anhydrite. So, they might dictate some formulation choices to avoid dissolutions. In that aspect, the synthetic fluid is preferred over water based muds, because it neither has free water nor interferes in the crossed salts solubility. The well caliper tends to be in gauge when compared with the saturated water base fluid.

TX 75083-3836 U.S.A., fax 1.972.952.9435. AbstractFast and non-progressive drilling fluid gelation is desired to prevent drilled solids sedimentation during pumps-off, while avoiding excessive pressure peaks when circulation is resumed. Gelation tendencies are normally higher at low temperatures typical of deepwater risers. Excessive pressure peaks can cause detrimental effects when fracture pressure is reached.Besides gelation issues, excessive pressures and/or difficulties to resume circulation have been observed during drilling operations in water depths greater than 1.800 m. The problem happened especially with the fluid volume filling the control lines, at the time of circulation restart. Two field cases of fluid freezing in choke and kill lines have been reported which led to riser and BOP removal to unplug the lines, with significant non productive time and high costs.The paper shows the results of an experimental study carried out to evaluate the rheological behavior and gelation properties of non aqueous drilling muds under low temperatures (bellow 4 o C) and high pressures (up to 5.000 psi). The study aimed to quantify pressure effects on freezing temperatures and to develop representative methodologies for the evaluation of thyxotropic properties of such fluids. Experiments included steady state and transient shear and oscillatory tests at cone-plate geometries. The final goals are to design additives and drilling fluid formulations with flow point lower than 0 o C at pressures higher than 2.500 psi and taylor made gelation profiles. Additionally modeling work was carried on to represent the time dependent behavior of relevant rheological properties at different temperatures and pressures. Such models were used to predict pressure peaks and compare them with real PWD data from ultra deepwater wells.

An order of magnitude increase in the Measurement While Drilling (MWD) signal strength was achieved while using a treated micronized barite (TMB) drilling fluid system. The MWD transmits downhole data critical for real-time data acquisition, geosteering, and formation evaluation.The MWD signal strength is one of the core variables that must be considered when drilling wells with increased measured depth. By displacing the conventional drilling fluid with the TMB System, the Acquisition System was able to recognize a ten-fold increase in signal strength from 0.1-0.2 psi to 1-2 psi. In addition, a 50% torque reduction was recorded and barite sag was not an issue. These performance characteristics make the TMB system a viable candidate for drilling high inclined wellbores and other critical wells.This paper covers a successful field trial showing the comparable MWD signal strength data with a treated micronized barite drilling fluid system carried out in the 8½-in. section of an HTHP exploration well offshore Brazil. IntroductionWith the ever increasing need to drill wells deeper and more pressure and temperature challenges, it is becoming crucial to have a drilling fluid system that can handle these adverse conditions. However, the drilling environment includes not only adverse downhole conditions, but also the fluid and equipment that must work in harmony. Drilling fluids must not only provide the necessary properties to manage the downhole conditions (e.g., prevent fluid influxes, promote wellbore stability), but also assist the functions of the drillstring and tools (e.g., cool and lubricate the bit, carry cuttings out of the hole).A common part of drilling fluid is the weight materials which are used to increase the density of drilling fluids and control subsurface wellbore pressures in many wells. Ground barite, a dense mineral, is the most common choice of weighting agent, especially for wells requiring higher mud weights. For a drilling fluid density of 2.0 g/cm 3 (16.7 lb/gal), 33 to 35 vol% of the drilling fluid is barite (Prebensen et al. 2009a). At this high loading level, the impact of barite on the rest of the drilling operation is important.A critical issue with API-grade barite and alternative high density weighting agents is their propensity to settle and separate from the fluid. Treated Micronized Barite (TMB) was designed to mitigate this sag. The extremely small particle size of TMB in which the majority of particles are less than 2 microns diameter, enables low-rheology non-aqueous fluids (NAF) to be formulated with considerably reduced risk of barite sag and settlement compared to fluids formulated with APIgrade barite which can be up to 75 microns in size (Taugbøl et al. 2005).