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 work presents the development of a methodology to numerically represent the acid treatment in a test plug, as well as to reproduce the different existing dissolution patterns and to obtain the corresponding values of pore volumes to breakthrough (PVBT). The numerical simulation is performed in a commercial CFD package that uses finite volume method. The modeling includes the effect of heterogeneous porosity/permeability and the presence of different types of minerals that impact the PVBT value, since they have different reaction rates at usual operation temperatures. Through these considerations, the formation of preferential channels, which are characteristics of the various patterns of wormhole, is captured by the numerical simulation.The goal of this development is the extraction of the characteristic PVBT curves for any pair formation/acid by numerical simulation. It is possible through the use of measured data during drilling, such as average porosity and range of variation, rock mineralogy, etc., and through the knowledge of reaction rates for each pair formation/acid. Using these data, the simulation is able to extract PVBT curves for different numerical test plugs, making it possible to prepare a statistical analysis that has greater significance than just a few experimental tests.The results show that PVBT curves obtained numerically are in good agreement with the physical behavior expected when compared to experiments. The variation range of the heterogeneous porosity and the presence of different minerals, which have distinct reactivity with acid, significantly change the behavior of the process for the same operating condition. Better understanding of acid treatment in carbonates (both limestone and dolomite) is important since the new Brazilian petroleum reservoirs are located below pre-salt layer. These rock formations are commonly subjected to acid stimulation in order to increase reservoir productivity. Therefore, the numerical PVBT curves obtained from this work could be used in simpler models to simulate the acid treatment in a reservoir scale. The use of more accurate curves can help the engineers to improve the design of operation conditions and, thus, increase the production capacity and distribute uniformly the treatment.

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This paper is aimed at presenting how Petrobras has faced inorganic scale problems in Campos Basin oilfields, Brazil. The approach used by Petrobras to predict, prevent and correct the problem of scale formation in tubulars and surface facilities is presented on a comprehensive basis. Radioactive-scale-related problems such as: storage, handling, disposal and equipment's de-commissioning are discussed as well. Both chemical and mechanical solutions and in-house developed techniques to cope with scale inhibition/dissolution are described as well. The requirement to assure high production level from deepwater wells demands high seawater injection rates. Herewith, then, it is presently underway the assessment of a nanofiltration system to remove sulfate ions from seawater and prevent barium sulfate scale from forming. Nanofiltration employment in deepwater Roncador field is also discussed in the paper. At the end of paper case histories are presented. Introduction Inorganic oilfield scale (OS) may be defined as water-soluble (inorganic) chemical compounds that precipitate out of solution and may agglomerate in the formation, perforations, gravel pack screens, tubing and surface facilities. OS consists of inorganic salts that come out of solution when incompatible waters, viz., formation water and injection water, are mixed and the resulting solution - under given conditions - becomes supersaturated with respect to an ion. OS may also precipitate out of solution when formation water equilibrium is upset by physical and chemical changes. As formation water moves upward, from reservoir to surface, the whole well fluid stream is submitted to a gradient of pressure, temperature and turbulence. Additionally, above the bubble point, a fraction of the dissolved gas separates out of both formation water and oil phases causing a major composition change in both phases of the well flow stream. As a consequence of this, formation water moves to another point of equilibrium by precipitating out of solution its supersaturated salts. Given adequate hydrodynamic conditions these precipitates may form OS. Nucleation sites, flow regime and surface roughness are among parameters that govern OS formation from original precipitates.1 The same phenomenon happens upon the oil phase and organic compounds may also precipitate out of solution. Notwithstanding with that, it is not within the scope of this work to discuss organic deposition. OS formation poses a tremendous impact on well productivity and is known as one of most troublesome problems in the oilfield.2 The most common OS are: calcium sulfate (gypsum), calcium carbonate (calcite), barium sulfate (barite) and strontium sulfate (celestite), iron carbonate (siderite), amorphous (opal) and crystalline silica (chalcedony).3 Radioactive (radium-based) OS are also known. Campos Basin Scenario The most common OS found in Campos basin are calcium, barium and strontium sulfates. Calcium carbonate scale occurrence is rare and local. Sodium chloride (halite) scales are also known. The presence of naturally-ocurring-radioactive-materials (NORM) in oifield scale has been known since early the 1980 s in Campos Basin area. This problem has happened upon in some fields located in shallow waters of the basin, which have been submitted to a continuos seawater injection program. It has been identified that these NORM-containing OS result from small amount of radium ions leached out from reservoir rock by injection water. A part of this radium salt co-precipitates with barium and strontium as sulfates. Another part of it remains soluble in the produced water.4

SbstractNowadays more and more unexpected uses for common materials have been observed, especially when recycled polymers are concerned. In this work, the viability for application of virgin and recycled poly(ethylene terephthalate) (PET vir and PET rec , respectively) and also poly(methylene oxide) (PMO) as granular materials (gravel) for gravel packing in sand control systems for unconsolidated sandstone reservoirs was studied. Polymer samples were tested in conditions similar to those observed in Campos Basin sandstone formations, in Brazilian Southwest (70 °C and 24.1 MPa). Samples were individually confined in roller cells with chemicals used in formation treatment: hydrochloric acid, pentapotassic DTPA salt (chelant Trilon CK) and in a mixture of diesel, xylene and butyl glycol. Mass loss was measured and the changes in molecular mass verified by size exclusion chromatography (SEC). Physical shape and grain size distribution were verified by scanning electron microscopy (SEM) and sieving tests. The effects over the polymeric gravel pack confinement resistance and permeability were evaluated using an API permeability cell. PMO proved to have a limited use, whereas PET rec and PET vir samples were not significantly affected, suggesting the viability of applying that recycled polymer in gravel packing for sand control in petroleum wells.