Traditional water based fluids tend to penetrate into shale formations, and interact with clay minerals, which results in clay swelling and wellbore instability. The larger content of clay in some deep water shales compared to regular onshore shales generates more wellbore instability problems. To reduce shale-fluid interaction, we need to reduce water invasion by sealing the pores and micro-fractures in shales. Therefore, the objectives of this study are to conduct pore pressure transmission (PPT) tests with test fluids that contain two new families of nanoparticles and to evaluate the major factors that affect pore pressure transmission. For the first time, Mancos Shale and Eagle Ford Shale have been investigated with PPT tests using fluids that contain nanoparticles in different sizes (10 nm, 20 nm, 30 nm, 40 nm), types (aluminum oxide, magnesium oxide) and concentrations (3%, 10%). Results show that nanoparticles of 10 nm size can delay the time needed to reach the equilibrium state to 48.2 hours, compared to 27.8 hours needed for Eagle Ford Shale treated with suspensions that contain 40 nm nanoparticles. Based on the test matrix, the better combinations to decrease pore pressure at the equilibrium state are 10% 10 nm Al2O3 for Eagle Ford Shale and 10% 30 nm Al2O3 for Mancos Shale. This relatively new plugging technique using nanoparticles has great practical potential for successful application in deep water drilling. A decrease in pore pressure transmission and the delay of the time to reach the equilibrium state will reduce problems of hydration and swelling in shale formations. This study can also help to define water based drilling fluid properties for the purpose of improving wellbore stability in deep water drilling.

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Many coalbed methane reservoirs and Devonian shale reservoirs are naturally fractured with part of the gas adsorbed in the low permeability matrix. The adsorption mechanism is controlled by reservoir pressure; during the depletion of the reservoirs, the adsorbed gas in the matrix is released as free gas flowing from the matrix to the fractures and then to the wellbore. In addition, these reservoirs are frequent layered. This paper presents an approximate analytical model for modeling commingled (multilayer) gas reservoir with sorption effects. Our work shows that this model can be developed based on an analytical model developed for slightly compressible liquid commingled systems. To take into account the nonlinearity of the total gas reservoir system, each layer has to be treated as a nonlinear system individually and combine all the individual single-layer solutions with the boundary condition at the wellbore. For this reason, we applied pseudopressure and pseudotime concepts in each layer. The pseudotime definitions take into account the nonlinearity coursed by both the pressure-dependent gas properties and the sorption effects in each layer, both of which we assume to be controlled by average pressure within the layer. We used a numerical simulator to verify our model. The results show that our model agrees well with the numerical simulator. INTRODUCTION Coal bed methane reservoirs and Devonian shale reservoirs arc considered important unconventional sources of gas. These reservoirs differ from conventional gas reservoirs in that a large part of gas is adsorbed in the low permeability matrix with the sorption mechanism controlled by pressure. As the reservoirs are depleted, the gas adsorbed in the matrix is gradually released as free gas flowing from matrix to fractures and then to the well bore. Fig. 1 is a plot of adsorbed methane content versus pressure for two isotherms. These isotherms are considered typical or average isotherms for a black shale and a gray shale, respectively, in the area of Pike County, Kentucky. When pressure is below a certain value, the adsorbed gas may account for as high as 50 to 60% of the total gas stored. Therefore, the adsorbed gas will play an important role in long term production. Production forecasts without desorption effects could be for too pessimistic. Some coalbed methane reservoirs and most Devonian shale reservoirs have low mobil water content. Some of them are properly considered as multilayer, naturally fractured reservoirs. The objective of this paper is to develop an approximate analytical model for modeling multilayer, naturally fractured reservoirs with single-phase gas flow, taking account of sorption effects.