Acidizing Gas Wells in the Merluza Field Using an Acetici Formic Acid Mixture and Foam Pigs Abstract This paper presents the laboratory testing of acid compositions and the planning, execution, and evaluation of the acidizing operations performed in the Merluza gas field, located offshore Brazil. Since the beginning of the production, the presence of calcium carbonate scale has been observed. Laboratory experiments determined that the most efficient acid mixture to remove that scale and to clean up perforations was 7% formic acid (HFor)/ 5% acetic acid (HAc) and that the best composition for matrix acidizing was saturated di-sodium EDTA. Regular HCl compositions were not recommended due to the nature of the tubing material (13Cr) and of the high reservoir temperature. The use of foam pigs to keep the acid at the desired position and to prevent the reaction products from decanting to the formation, and the application of the organic acid mixture to clean up the perforations were very successful, increasing the gas production rate by 740.000 m3/day. Because of this, the matrix acidizing with EDTA was postponed. These results show that Hac/H for compositions are a viable solution to acidize wells where HCl cannot be used, such as HPHT wells, or where production equipment contain chromium. P. 67

This study proposes, through the coupling of a linear filtration formulation (laboratory configuration) and a radial single-phase formulation (wellbore vicinity), to predict fluid-invasion depth-ofdrilling fluid filtrate in the reservoir rock. Modeling is validated with linear and radial laboratory tests, as well as with resistivity logs run in offshore wells from Campos basin, offshore Brazil.The proposed methodology is required for optimum drillingfluid design to be used in the drilling of reservoir sections in both exploratory and developmental wells in Campos basin. Drilling-Fluid Design Criteria for Minimum InvasionAn adequate drilling-fluid design requires bridging-agent size distribution and concentration optimization. The ability of the fluid system to prevent invasion is normally evaluated by standardized static-filtration experiments. In these tests, the fluid is pressurized through a filter paper or into a consolidated inert porous medium. The volume that crosses the porous core is monitored continuously. Santos et al. 5 present an experimental study questioning the reliability of filter-paper-filtration experiments to reproduce invasion into unconsolidated reservoirs.The main goal of this study is to establish a simplified methodology to correlate laboratory filtration tests and radial invasion in the reservoir. In other words, to define laboratory filtration requirements for a given accepted invasion. This task will be performed in three different steps: (1) modeling the laboratory linear experiment (flow through a consolidated porous medium),

Drilling and completing either exploratory or development wells in Pre-Salt prospects present several challenges. The wells are located in very deep waters, beyond 2,000 m WD and they are also deep wells, with more than 5,000 m TVD. Pressure and temperature is normal, but contaminants such as H2S and CO2 represent an additional difficulty. Most of all, drilling through salt layers as thick as 2,000 m presents the most challenging aspect of these wells. Directional, extended reach (ERW), horizontal and multilateral wells will be evaluated for production development, but the reservoir is a carbonate horizon just below the salt, meaning that high angle navigation and multilateral joints will be located inside the salt layers. These wells measured depths will reach 8,000 m or more. The salt geo-mechanical loads on the casing and cementing will require high strength materials and high capacity rig equipment. The competency of the salt formations and, most of all, of the carbonate reservoir, totaling more than 3,000 m to be drilled, will require special BHA and bit design to increase penetration rates, thus reducing rig time. Carbonate reservoir will require production liner, perforations/slots and stimulation treatments designed to maximize production. Although these challenges could be overcome today, with existing technology, due to the current high costs scenario, well construction time and risks must be minimized. Some technology development is already underway to address these issues, but most of the gains can be materialized without new technology, by proper engineering design, risk management and learning curve acceleration. After 8 wells drilled in Pre-Salt prospects, Petrobras has already gained important know-how in these projects, but there is still a long way ahead. In the following years, well construction campaign for an Extended Well Testing (EWT) and a Pilot Production System in the Tupi Pre-Salt area, plus additional exploration wells, will provide field test opportunities for development and optimization of well engineering techniques and equipment. This paper will present the highlights of Petrobras E&P program to make the best use of these opportunities to leverage the well construction learning curve. Introduction In recent years, exploration activities in Brazil began to focus on the São Paulo Plateau, a prominent regional topographic feature in water depths ranging from 2,000 to 3,000 m. A continuous Aptian evaporitic sequence, in some points thicker than 2,000 m (Fig. 1), exists in this region, contrasting with the very thin marine section above. The reservoir section occurs just below the evaporitics and is composed by microbialite carbonates. In such a Pre-Salt section, with variable thickness, a few exploratory wells were drilled. Petrobras is now facing a challenge similar to that one encountered during the discoveries of deep-water turbiditic reservoirs in Campos Basin. Salts belong to a group of sedimentary rocks called evaporites, resulting from sea water evaporation. Submitted to a sustained constant stress, evaporites can suffer considerable deformation, in a behavior denominated " salt creeping??. Due to this characteristic, salt intrusions and domes can be found in many sedimentary basins, associated with either high pore pressure zones, or fractured zones (" rubble zones??).

This paper was presented by an SPE Program Committee following review of Information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the or SPE, their officers, or members. Papers presented at SPE meetings are subject to publication review by editorial Committees of the IADC and SPE. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Write Publications Manager, SPE, P.O. Box 833838, Richardson, TX 75083-3836 U.S.A. Telex, 730989 SPEDAL. Abstract It is known that the plastic Bingham model is inadequate to represent some types of drilling fluids, such as low solids and emulsions, especially at medium and low shear rates. Previous experiments on carrying capacity concluded that the average annular velocity and rheological properties affect the fluid transport more significantly than other parameters. Many of these experiments refer to the yield point of the Bingham model, calculated at high shear rates as the most important parameter. This experiment studies how the initial gel strength and plastic yield point affect the carrying capacity of the drilling fluids employing the transport ratio concept. For this purpose the terminal settling velocity of the drilled solids through quiescent fluids was experimentally determined. The results showed a better correlation with the initial gel strength than with the yield point. Also, the analysis of the results demonstrated that a gel strength of about 1.92 Pa (4.0 lbf/100 ft2) is necessary and substantial to obtain a transport ratio higher than 0.50 when the annular velocity is in the range of 0.41 m/s (80 ft/min) to 0.66 m/s (130 ft/min), using low solids and polymer drilling fluids. For any type of water based drilling fluids a gel strength in the range of 3.35 Pa (7 lbf/100 ft2) to 4.79 Pa (9.0 lbf/100 ft2) is sufficient to remove the cuttings at more than 0.50 of transport ratio, even when the annular velocity is about 0.25 m/s *50 ft/min). Introduction The transport of drilled solids from the bottom hole to the surface, throughout the annulus, is one of the main objectives of the drilling fluids. The terms removal velocity and transport ratio are often used to estimate the ability of a drilling fluid to transport drilled solids in a vertical well. The removal velocity is a mean value of the relative cuttings velocity which is equal to the difference between the average annular fluid velocity and the ave rage slip velocity of the cuttings. (1) Vr = Va − Vs The average annulus velocity is defined as a function of the flow rate and the dimensions of the annulus, while the slip velocity is defined as the average velocity at which the particles tend to settle in a fluid. This velocity depends on the size of the particle, its geometry, its density, and properties of the fluid, mainly rheological and density. The transport ratio is defined as follows: (2) Va Vr = Rt = = 1 − ( Vs Va ) The analysis of the equation (2) shows that the transport ratio increases when the slip velocity decreases or the annular velocity increases. If the slip velocity is equal to zero, then the transport ratio will be transported with the same annular velocity. Conversely, if the slip velocity is high the transport ratio will be low. In this case, note that the concentration of the solid in the annulus will increases.

The anticipation and remediation of operational problems while drilling an oilwell is the main goal of real time measurements of drilling parameters, such as bottomhole pressure, flow rate, pump pressure, torque, drag, among others. The petroleum industry has spent a great amount of financial resources to ensure the quality and availability of these data, but the knowledge for a correct analysis and interpretation of them is still far from being spread among the rigsite teams and drilling engineers. Nowadays, the interpretation of real time drilling data to identify possible operational problems is done by a drilling analysis specialist. However, this can be a very subjective job since it depends on the specialist experience. These analists also take their decisions based on intuition and qualitative rather than quantitative criteria. Petrobras has developed a computational tool (called PWDa) to interpret real time drilling data, predicting and analyzing drilling operational parameters (such as pump pressure, bottomhole pressure, torque and drag). The software detects abnormal behaviors (such as an unexpected increasing trend on bottomhole pressure) and establishes quantitative criteria in order to identify a possible cause, suggesting corrective and/or preventive actions. The main goal of the software is the establishment of an automated methodology to interpret operational parameters in real time helping the drilling engineers to take right and fast decisions. The software is being currently implemented at Petrobras Real Time Operations (RTO) rooms and is providing good results. Over 70 wells have already been monitored with PWDa and several operational problems (such as washout, mud losses, bit wear, downhole motor fail, deficient hole cleaning, pore pressure increments, etc) were successfully identified, allowing the operators to take fast decisions and avoiding riskier situations. The wells monitored include deep water exploratory wells (mostly), directional development wells and extended reach wells. This work aims to highlight the benefits generated by the implementation of the technology. The interaction with the drilling team, including operator and service company members will be discussed. Introduction The analyzis of PWD (Pressure While Drilling) data and other operational parameters (such as rate of penetration, standpipe pressure, flow rate, torque, drag, etc) is an important tool to identify and prevent several operational problems (Aragao et al). The real time interpretation of these data may be very useful to reduce non productive time, risks and operational costs. According to Teixeira et al, most of events and problems have direct or indirect impact on bottomhole pressure and standpipe pressure. Some of them may also affect torque and drag. Problems like poor hole cleaning, annular obstructions, wellbore collapse, kicks, washouts and mud losses will affect the amount of solids in the annular space and/or friction losses and, therefor, will directly affect standpipe and bottomhole pressure (Aragao, et al, 2005). Thus, the analysis of pressure data is a key element to identify and prevent operational problems. Additionaly, when other parameters are simultaneously analyzed (modlogging measurements, for instance), the interpretation becomes much richer.