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During the drilling of oil wells, the fluid interacts with the shales layers in the walls of the well, with the cuttings and at the contact drill bit-rock. The physical-chemical interaction between shales and the drilling fluids is still a well engineering unknown, but many problems that happen during the drilling is credited to this interaction.The physical-chemical interaction rock/fluids are consequences of both water and ionic species fluxes from and to the rock. The mechanisms of transport in shales, like osmosis, reverse osmosis, diffusion of ions and hydraulic pressure, can cause chemical changes in the shales and fluids, like cation exchange capacity, chemical composition of mud filtrate, the shale matrix and pore fluids, hydration or dehydration of shales (Chenevert, 1969) and swelling pressure Santarelli and Carminati, 1995). Also, these mechanisms change the mechanic properties of the fluids, like the weight and viscosity, that are important to stability of well and the retard the fluid invasion in shales (van Oort, 1994; Bol et al., 1996). This paper is a brief extract of a wider project, currently in development at the Laboratory of Rock-Fluid Interaction of PUC-Rio, and that aims to study the behavior of preserved shale samples when immersed in aqueous solutions. Also, special attention was paid to the fluid properties, which include: electro-chemical, chemical and mechanical properties of the fluid. EXPERIMENTAL STUDY OF INTERACTION SHALE-FLUID THROUGH IMMERSION TESTS ABSTRACTThe present work has as objective the study of the behavior of preserved shale samples when immersed in aqueous solutions. The obtained results show that the solutions presented high variations of pH, salinity and electric conductivity, what indicates ionic migration of salts from the rock to the fluid, and small variations of Redox potential. Chemical analysis indicate strong migrations of ions from the rock to the fluid. It can also be observed that the solutions become cloudy, denser and more viscous. Besides, the samples suffer elevations of its water content, small variation of its cation exchange capacity and chemical composition, loss of solid material from superficial disintegration and the development of fractures in the cores. This work contributes to the understanding of the shale behavior in presence of drilling fluid water base.

This paper describes an integrated methodology to characterize shales from an engineering point of view. Shale samples from offshore Brazil were used throughout the study. The proposed methodology includes laboratory tests designed to characterize the rock individual constituents, i.e., solid particles and pore fluid, and to describe the rock microstructure. Complementary laboratory tests on the same materials indicated low potential of reactivity when in contact with saline solutions in spite of the presence of highly expansive clay minerals. The paper suggests that other elements besides simply the characteristics of the clay minerals should be considered when evaluating the potential of reactivity of shales. Introduction The drilling of shaly sequences of inclined wellbores often needs constant interruptions to solve problems such as tight hole, excessive solids in the drilling fluid and bit balling. The consequences are: increase in drilling time and costs. Ten years old estimates indicate that these drilling problems, on average, are responsible for 20 to 30% of the drilling costs and, amongst these, 80 to 90% occur when drilling through shales1,2. Current drilling scenarios of highly inclined wells and large water depths have kept the industry searching for solutions to minimize the impact of such problems. Cases of wellbore instabilities when drilling through shales have been reported for over 60 years3. The first attempts to face instabilities in shales were based in empirical approach in which the signs of instabilities were reported generating systems of classifications oriented towards identifying the eventual drilling problems4,5. Since then, it was established that the most likely cause of instabilities in shales were related to the clay minerals present in the shales and its expansive characteristics when exposed to the drilling fluids. Attempts to follow a rational approach to analyze problems of wellbore instabilities date from the 60s when experimental studies were first carried out6. Next, several studies were carried out to define more appropriate modes to drill wells through shales considering not only the drilling fluid density but also its chemical composition7–15. Studies on physico-chemical phenomena (ion transport and hydration of clay minerals) are quite recent and practical application of the results is still limited16. Most of the shale test results reported prior to 1990 were carried out on samples that had lost part of its natural, down hole fluid content due to exposition or inappropriate storage prior to testing. Several studies indicated that swelling effects or reactions between shale and fluids observed during experiments could be interpreted as caused by the loss in saturation of the samples and not only by the presence of expansive clay minerals17–19. Actually, fully preserved shale samples did not show any indication of interaction even when immersed in deionized water20. After these new findings, it became clear that some effort would have to be placed in understanding which elements of shales would have to be described in order to evaluate the potential destruction of its structure when in contact with fluids.

Summary This paper describes the study of dissolution and mineralogical alteration caused by saline carbonated water injection (CWI) and its effects on the petrophysical properties (porosity and permeability) of limestone samples from the Mupe Member, composed of lacustrine microbialites from the Upper Jurassic, part of the Purbeck Group lower portion. These limestones are a partial analog of the Brazilian presalt Aptian carbonates, the most important oil reservoir in Brazil. These reservoirs present large amounts of CO2 that are reinjected into the formation, which given the high reactivity of carbonate rocks in the presence of carbonic acid generated by the reaction between CO2 and water, can cause damage to the rock’s pore space. To achieve the proposed objectives, four laminated/massive samples with very low permeability (<5 md) and two vuggy/microbial samples with very high permeability (>1,700 md) underwent laboratory tests carried out before, during, and after CWI, including gas porosity and permeability measurement, nuclear magnetic resonance (NMR), microcomputed tomography (micro-CT), and ion chromatography. X-ray diffraction (XRD) analysis and petrographic thin-section observations were also performed. The experimental results showed that samples with high permeability showed a small decrease in permeability, possibly indicating formation damage, while low-permeability samples presented a significant increase in permeability with little change in porosity, indicating feasibility for carbon capture and storage (CCS) in similar samples in likewise experimental conditions (20°C and 500 psi). For samples with more pore volumes injected, the pressure stabilization seems to have favored dissolution in the later injection stages, indicated by the highest output of calcium ions. In all samples occurred salt precipitation during injection, especially in the more heterogeneous rocks, presenting a possible issue.

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Introduction The Muddy and Dakota sands, more commonly known as the "D" and "J" sands, respectively, of the Denver-Julesburg Basin are correlative over a large area. It is reasonable to believe, therefore, that depositional environment throughout the Basin was comparable. Local variations in sand development do occur, however, and productivity is often governed by permeability as well as structural position. Experience indicates permeability is commonly a function of cementing material. While cases of siliceous or calcareous cementing have been observed, the bonding material is, for the most part, clay. Under the latter circumstance, clay should bear some relation to permeability. Similarly, gamma radiation should bear some relation to the amount of clay. This study was undertaken to determine if a cross relation exists between gamma radiation and permeability. Results of Investigation A qualitative relation does exist between gamma radiation and permeability for clay-bonded Muddy and Dakota sands of the Denver-Julesburg Basin. This is illustrated graphically by Fig. 1, which shows corrected gamma ray deflection vs permeability for five wells over an area approximately 50 miles long and 8 miles wide. The "corrected" gamma ray deflection cannot be read directly from the gamma ray survey in all cases. It became apparent early in the investigation that methods would have to be developed for converting all gamma ray surveys to a common deflection scale and to correct for thin bed effects. Common Scale Deflection Because all logs are not recorded in the same calibration units or at the same sensitivity, it was felt they could be most readily converted to a common scale by measurement of deflection in inches from zero. Initially, four wells in the Jacinto field of Nebraska were carefully correlated, and selected intervals were planimetered to obtain average deflections.

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